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.- , , " I 1 )..-, j OPERAlING REVENUES: Revenues OPERATING EXPENSES: Operation

-.Fuel Purchased

& Interchange power, net Other Maintenance Depreciation

& amortation Taxes other than ncome taxes Federal and State inoome taxes$ 1,072,707 341,767 78,751 169,013 109,50 109,862 65,657 53,363-, A ., Total Operating Expenses 927,913 OPERATING INCOME OTHER INCOME (EXPENSES):

Allowance for equity funds used during construction Income from subsidiary Other, net INCOME BEFORE INTEREST CHARGES INTEREST CHARGES: Interest on longterm debt Allowance for debt funds used during construction Amortization of debt discount, premium and expenses, net Other Interest charges Net Interest Charges NET INCOME DIVIDENDS ON PREFERRED STOCK 144,794 5,529 1,075 i.)145,369 5,992.(2A423)3,337_ 249 57,155 88,214 6,072 I .1 ..........i 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 accounting practices of the Company on the basis of Interim figures and Is subject to audit and end of year adjustments.

ALABAMA POWER COMPANY BALANCE SHEET CONSOLIDATED WITH ALABAMA POWER CAPITAL TRUSTS IV & V (Stated n Thousands o Dolars)ASSETS UTLJTY PLANT.Plant in service, at original cost ....................

.. ...._ .._...Less -Aooumuiated provision for depredation and amobmtion.............

...Nuclear hAL at amortized

.. ..................

.-Constrction ruk in vxoo ss..........

...........................

......At Uarch 31. 2006,$ $ .15541,825$ 6,997,337$ 9.454.488$ 128,0 W23,939.S10.104,605 Al March 31, 2005 i ',769,038$ ..410.2006.4783806 9,691.380 OTHER PROPERTYAND NVESTMENTS:

Equity Investments In ..... ....Investment in umconsoldated abidlarles.....

Nuclear deconunissioning busts.....

...................................

Miscel anao ....... .. ... ...._ _ _..$ 37,581$ 9.530$ 476.961 S. 33,138$ 659,210 47,363 0.279 44S,277 227.771 62 WM~CURRENT ASSETS: Cash ..._._ ......... ._ ....... _.... ... _._Spedial Deposits .. ..... .__ ... _._ ._ .. ._........

.....Tempoary cash hnestnts.......................

Investment securrtes.....

.................

... ..........

Receivables

.Customer accounts rsoelvabW

.. .... ..........

Other accounts and notes scehabe........_....

Affilatad c panes ._. ...Accunitated provisian br uncollectibe accounts Rel.idable Income laxes ..... ...Fossi el ,stoc, at average casL...__....

-..... ...... .......................

-..... ..............

.............. .............

S S S S 11 13,171 110400 M965 43,230 59,130 (6,167)3,408 134,612 Materials and suplies, at average osL .......................

Allowance hventbry..........._

Prepayments

-Income taxes ..............

Other. ...... .. ._, Other current assets -SFAS 133. .....Vacation paydeferred

......._._. _ ...Debt expense. being .Debt redemption evpense, being d..................................

Amated mi.oellaneous qawat p -..............

Prepaid pension cost .............

...............

ReT trya ssets..................

...... ..I llsce llaneous ........ _ _._._._._...______

__.____TOTAL ASSETS __._. _ ._w~__. _~___18,625 0 o S S'12,659 S I 9 4 .3 8 II 24=68 I 44.985 0 1'.M6.040) 11 .. .38.92 S 09.576 S 4 , 6 5$ 521.211$ 8151.687 S 107 .073$ I 2 3.0 2 S X 3 .646.76 398.651 518.338 27,444 84,087 I, # O 61.171 3B,494 51,1111O 29.60 tO7,347 493,456 653,UO_ 4.068$ 12,1S676.67 41261200M

+

This statement reflects the usual accounting practices of the Company on the basis of hiterim figures and Is subject to audit and end of year adjustments.

AABAMA POWER COMPANY BALANCE SHEET CONSOLIDATED WITH ALABAMA POWER CAPITAL TRUSTS IV & V.(Stated in Theusands of Dollars)CAPITALIZATION AND U^ABIJTMS CAPITALIZATION:

.__ ._ -.I I I Preferred stock .. ....... ... ..... ....._Company obigated mandatorD redeemable preferred securities

....Long4tern debt .. .............

_ ____Al Mlarch 31, 2006$ 3,769.305...... S 465,047 S 309.279_$ 4,356,731 e,900o362$Al March 31, 2005 3.605.473 464.948 309.279 3,35,527 8,3156227 CURRENT LIABBLITIES:

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

....L 4err n debt due or lo be redeemed Mn oe ysar.................._

Notes payable to banks....

_..............._._._._._

... .......Commercial paper ... .........

.._ .._ .. .._ ......... .Accounts payable.Affiliated ompanes. ..............

..... .........Other-_ ._ -'_ ._.___. .___Customer deposits.__

_.......___._

.._ ._ _.. _ __ _._Taxes accrued -Federal and state Incom e ........_.___.Other .... ..... ....._ ..........hnterest .cw_ _._ ._. ... _._ ...... .......... _.............

xued tnterest Paybce bo Uced Subs.........................................

Vacation pay acued............

.__ .... ..Miscellaneous

.. ..... ......DEFERRED CREDITS AND OTHER LIABLITIES:

Accumulated deferred hIcome taxes............................

Accumulated deferred hwestment taxradlt..._

_ _._.__.Asset Retirement Ob flonL........................

_ _ __Prepaid capacdty reve s nets...Reguatory liabilities

..... ..... _ ._ .._. .. .______Accumulated miscelaneous peratftg paislons.........................................

Natural disaster reserve ........._ ._ _ _Miscellaneous

.. ...............

TOTAL CAPITALIZATION AND UBLmES.........

....... ....S S S C16.3M,645, r .0 395.006 0 0 1 , S$$114.826 1J7,639 t8,877 10925 144,393 6t1460$ 124.120.$; 60,451$ 6S,383 S 8.370.5 .._ 3.6 S 106598 37051-48,335 61,744 8.119 3S.494 65.290 947.995 S 2.06M M7$ 194.58 S. 453.450 S 100.744 S .S2. 3.698$ 824,310 S .628.957 S __13.6J48.6

• 1,903,332 202.614 390.051 114,932 6.541 4.471 782,161 3,41S 264 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 Actual 2006 Projections Net Income Less Dividends Paid Retained Earnings Adjustments:

Depreciation and Amortization Deferred Income Taxes and Investment Tax Credits Allowance for Equity Used During Construction Total Adjustments

$ 532,184 432,659 99,525$ 482,369 464,889 17,480 498,914 517,326 106,765 (20281)585,398 38,369 (19.425)636,270 Internal Cash Flow$ 684.923 S 553,750$ 138438 Average Quarterly Cash Flow$ 1711231 Percentage Ownership In atl Operating Nuclear Units: Joseph M. Farley Units 1 and 2 100%Maxdmum Total ContingentL Uability$ 3,00 i 2005 Annual Report ALABAMA POWER COMPANY 4W ALABAMAAZ~

POWER A SOUTHERN COMPANY Always on M 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 statements of capitalization of Alabama Power Company (the "Company") (a wholly owned subsidiary of Southern Company) as of December 31, 2005 and 2004, and the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2005.These financial statements are the responsibility of the Company's management.

Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

The Company is not required to have, nor 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 appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.

Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

We believe that our audits provide a reasonable basis for our opinion.In our opinion, the financial statements (pages 23 to 50) present fairly, in all material respects, the financial position of Alabama Power Company at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.(C Lf Birmingham, Alabama February 27, 2006 3 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Alabama Power Company 2005 Annual Report OVERVIEW Business Activities Alabama Power Company (the Company) operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast.

Many factors affect the opportunities, challenges, and risks of the Company's primary business of selling electricity.

These factors include the ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover rising costs.These costs include those related to growing demand, increasingly stringent environmental standards, fuel prices, and restoration following major storms.On July 10, 2005 and August 29, 2005, Hurricanes Dennis and Katrina, respectively, hit the coast of Alabama and continued north through the state, causing significant damage in parts of the Company's service territory including the Company's distribution and transmission facilities.

Approximately 241,000 and 637,000, respectively, of the Company's 1.4 million customers were without electrical service immediately after Hurricanes Dennis and Katrina.In 2005, the Company successfully completed a retail rate proceeding with the Alabama Public Service Commission (PSC) to recover the costs associated with these storms and to replenish the Company's natural disaster reserve. In other actions, the Alabama PSC also approved a higher fuel recovery rate and amended the Company's Rate Stabilization and Equalization Plan (Rate RSE) to use forward-looking test periods. These regulatory actions are expected to assist the Company's continued focus on providing reliable electrical service to customers while maintaining a stable financial position.Key Performance Indicators In striving to maximize shareholder value while providing cost effective energy to customers, the Company continues to focus on several key indicators.

These indicators include customer satisfaction, plant availability, system reliability, and net income. The Company's financial success is directly tied to the satisfaction of its customers.

Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company's results.Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation fleet operations during the months when generation needs are greatest.The rate is calculated by dividing the number of hours of forced outages by total generation hours. Peak Season EFOR performance excludes the impact of hurricanes and certain outage events caused by manufacturer defects.The 2005 Peak Season EFOR exceeded target levels primarily due to equipment malfunctions at Plant Barry units 5 and 6, which resulted in unexpected outages.Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected capital expenditures.

The 2005 performance was above target on these reliability measures.

Net income is the primary component of the Company's contribution to Southern Company's earnings per share goal. The Company's 2005 results compared with its targets for each of these indicators are reflected in the following chart.Key 2005 2005 Performance Target Actual Indicator Performance Performance Customer Top quartile in Satisfaction customer surveys Top quartile Peak Season 2.75% or less 3.83%EFOR Income $0mlo $8iin Net Income $501 million $508 million See RESULTS OF OPERATIONS herein for additional information on the Company's financial performance.

The strong financial performance achieved in 2005 reflects the focus that management places on these indicators, as well as the commitment shown by the Company's employees in achieving or exceeding management's expectations.

Earnings The Company's financial performance remained strong in 2005 despite the challenges of major hurricane restorations and rising fuel costs. The Company's net income after dividends on preferred stock of $508 million in 2005 increased

$27 million (5.6 percent) over the prior year. This improvement is primarily due to retail and wholesale revenue growth, increases in transmission revenues, partially offset by higher non-fuel operating expenses.4 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report The Company's 2004 net income after dividends on preferred stock was $481 million, representing an $8 million (1.8 percent) increase from the prior year. This improvement was primarily due to retail sales growth, increases in other revenues, and lower interest expense, partially offset by higher non-fuel operating expenses.The Company's 2003 net income after dividends on preferred stock was $473 million, representing a $12 million (2.5 percent) increase from the prior year. This improvement was due primarily to higher retail sales, higher sales for resale, increases in customer fees revenues, and lower interest expense, partially offset by higher non-fuel operating expenses.The ROE for 2005 was 13.72 percent compared to 13.53 percent in 2004 and 13.75 percent in 2003.RESULTS OF OPERATIONS Amount 2005 2004 2003 (in millions)Retail -- prior year $3,293 $3,051 $2,951 Change in -Base rates 35 41 51 Sales growth 50 48 68 Weather 18 12 (61)Fuel cost recovery and other 225 141 42 Retail -- current year 3,621 3,293 3,051 Sales for resale --Non-affiliates 551 484 488 Affiliates 289 308 277 Total sales for resale 840 792 765 Other operating revenues 187 151 144 Total operating revenues $4,648 $4,236 $3,960 Percent change 9.7% 7.0% 6.7%A condensed income statement is as follows: Increase (Decrease)

Amount From Prior Year-2005 2005 2004 (in millions)2003 Operating revenues $4,648 $412 $276 $250 Fuel 1,457 271 119 98 Purchased power 457 44 98 66 Other operation and maintenance 1,044 97 26 67 Depreciation and amortization 427 1 13 15 Taxes other than income taxes 249 6 14 11 Total operating expenses 3,634 419 270 257 Operating income 1,014 (7) 6 (7)Total other income and (expense)

(197) 6 30 20 Income taxes 285 (29) 23 (2)Net income 532 28 13 15 Dividends on preferred stock 24 1 5 3 Net income after dividends onpreferredstock

$ 508 $ 27 $ 8 $ 12 Retail revenues in 2005 were $3.6 billion. Revenues increased

$328 million (10.0 percent) in 2005, $242 million (7.9 percent) in 2004, and $100 million (3.4 percent) in 2003. These increases were primarily due to increased fuel revenue and retail base rate increases of 0.5 percent in April 2005, 1.0 percent in January 2005, 0.8 percent in July 2004, and 2.6 percent in July 2003. See FUTURE EARNINGS POTENTIAL

-"PSC Matters" herein and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information.

Fuel rates billed to customers are designed to fully recover fluctuating fuel and purchased power costs over a period of time. Fuel revenues generally have no effect on net income because they represent the recording of revenues to offset fuel and purchased power expenses.See FUTURE EARNINGS POTENTIAL

-"PSC Matters-Retail Fuel Cost Recovery" herein and Note 3 to the financial statements under "Retail Regulatory Matters -Fuel Cost Recovery" for additional information.

Sales for resale to non-affiliates are predominantly unit power sales under long-term contracts to Florida utilities.

Revenues from unit power sales contracts have both capacity and energy components.

Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts.

Energy is generally sold at variable cost. These capacity and energy components of the unit power contracts were as follows: Revenues Operating revenues for 2005 were $4.6 billion, reflecting a$412 million increase from 2004, The following table summarizes the principal factors that have affected operating revenues for the past three years: S MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report-Unit power -Capacity Energy Total 2005 2004 2003 (in thousands)

$147,609 $134,615 $130,022 169,080 146,809 145,342$316.689 $281,424 $275.364 No significant declines in the amount of capacity are scheduled until the termination of the contracts in 2010.Short-term opportunity energy sales are also included in sales for resale to non-affiliates.

These opportunity sales are made at market-based rates that generally provide a margin above the Company's variable cost to produce the energy. Revenues associated with other power sales to non-affiliates were as follows: million increase from rent from associated companies primarily related to leased transmission facilities.

Other operating revenues in 2004 increased

$7.0 million (4.9 percent) from 2003 due to an increase of $7.7 million in revenues from gas-fueled co-generation steam facilities

-- primarily as a result of higher gas prices -and a $2.4 million increase in revenues from rent from electric property offset by a $2.0 million decrease in transmission revenues.Other operating revenues in 2003 increased

$47 million (48.6 percent) from 2002 due to an increase of$19.4 million in revenues from gas-fueled co-generation steam facilities

-- primarily as a result of higher gas prices-- and a $14.8 million increase in revenues from Alabama PSC approved fees charged to customers for connection, reconnection, and collection when compared to the same period in 2002.Since co-generation steam revenues are generally offset by fuel expense, these revenues did not have a significant impact on earnings.2005 2004 (in thousands) 2003 Other power sales -Capacity and other $116,181 $ 90,673 $ 96,263 Variable cost of energy 118,537 111,742 115,829 Total $234,718 $202,415 $212,092 Revenues from sales to affiliated companies within the Southern Company electric system, as well as purchases of energy, will vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliated sales and purchases are made in accordance with the Intercompany Interchange Contract (IIC) as approved by the Federal Energy Regulatory Commission (FERC). In 2005, sales for resale revenues decreased

$19.4 million primarily due to a 20.7 percent decrease in kilowatt-hour sales to affiliates as a result of a decrease in the availability of the Company's generating resources due to an increase in customer demand within the Company's service territory.

Sales for resale revenues increased

$31.1 million in 2004 due to increases in fuel-related expenses.

Sales for resale revenues increased

$89.1 million in 2003 due to increased capacity payments received from affiliates.

Excluding the capacity revenues, these transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through the Company's energy cost recovery clause.Other operating revenues in 2005 increased

$35.0 million (23.2 percent) from 2004 due to an increase of $20 million in revenues from gas-fueled co-generation steam facilities primarily as a result of higher gas prices, and$7.7 million increase in transmission revenues and a $3.9 Energy Sales Changes in revenues are influenced heavily by the volume of energy sold each year. Kilowatt-hour (KWH) sales for 2005 and the percent change by year were as follows: KWH Percent Change 2005 2005 2004 2003 (millions)

Residential Commercial Industrial Other Total retail Sales for resale -Non-affiliates Affiliates Total 18,074 14,062 23,350 198 55,684 4.1%1.7 2.2 0.2 2.7 2.4%2.8 5.8 (2.4)3.9 (9.4)(23.2)(2.2)(2.5)%0.7 2.3 (1.1)0.3 9.9 6.5 2.9 15,443 (0.3)5,735 (20.7)76,862 (0.1)Retail energy sales in 2005 were 2.7 percent higher than 2004 despite interruptions during Hurricanes Dennis and Katrina. Energy sales in the residential sector led the growth with a 4.1 percent increase in 2005 due primarily to increased demand. Commercial sales increased 1.7 percent in 2005 primarily due to continued customer growth. Industrial sales increased 2.2 percent during the 6 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report year with chemical, primary metals and automotive leading the growth in industrial energy consumption.

In addition, the paper sector chose to purchase rather than self-generate which contributed to increased sales.Energy sales in the residential sector grew by 2.4 percent in 2004 primarily due to continued customer growth and a return to normal summer temperatures.

Commercial sales increased 2.8 percent in 2004 primarily due to continued customer growth. Industrial sales rebounded 5.8 percent during the year with primary metals, chemical, and paper sectors leading the growth.In 2003, residential energy sales experienced a 2.5 percent decrease over the prior year and total retail energy sales grew by 0.3 percent primarily as a result of milder-than-normal summer temperatures compared to the previous year. Although retail sales to industrial customers increased 2.3 percent in 2003 and 3.1 percent in 2002, overall sales to industrial customers remained depressed due to the effect of sluggish economic conditions.

Assuming normal weather, sales to retail customers are projected to grow approximately 1.3 percent annually on average during 2006 through 2010.Total Operating Expenses In 2005 total operating expenses increased

$419 million (13.0 percent) to $3.6 billion. This change from 2004 includes an increase in fuel expense of $271 million (22.8 percent) related to higher natural gas and coal prices. In addition, purchased power expenses increased

$45 million (10.8 percent) primarily due to a 17.9 percent increase in purchased power prices. Maintenance expenses increased$48 million primarily from transmission and distribution expense. These increases are mainly a result of the Alabama PSC accounting order to recognize the previously deferred costs of Hurricane Ivan storm damage restoration and to partially replenish a balance in the natural disaster reserve. See Note 3 to the financial statements under"Retail Regulatory Matters -Natural Disaster Cost Recovery" for additional information.

Total operating expenses in 2004 grew $270 million (9.2 percent) to $3.2 billion. This increase over the previous year was primarily related to an increase in natural gas and coal prices. In addition, purchased power expenses increased

$98 million (31.0 percent) primarily due to a 71.7 percent increase in energy purchased, while purchased power prices decreased by 1.9 percent. Depreciation and amortization expense increased

$13 million (3.1 percent)primarily due to an increase in utility plant in service.The total operating expenses in 2003 were approximately

$3.0 billion, an increase of $257 million (9.6 percent) over the previous year. This increase is mainly due to a $98 million increase in fuel expense primarily related to an. increase in the average cost of natural gas and coal. In addition, purchased power expenses increased a total of $66 million, maintenance expense increased

$30 million primarily related to transmission and distribution overhead lines, and depreciation and amortization expense increased$15 million.Fuel and Purchased Power Expenses Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of fossil and nuclear generating units and hydro generation.

The amount and sources of generation and the average cost of fuel per net KWH generated and the average cost of purchased power were as follows: Total generation (billions of KWHs)Sources of generation (percent)

--Coal Nuclear Hydro Gas Average cost of fuel per net KWH generated (cents)Average cost of purchased power per net KWH (cents)2005 2004 2003 71 70 72 67 19 6 8 65 19 6 10 64 19 8 9 2.02 1.69 1.54 6.49 4.79 3.61 Fuel expense increased 22.8 percent In 2005 primarily due to an increase in the average cost of fuel as a result of a 26.5 percent increase in the average price of natural gas and an 18.5 percent increase in the average coal price.Fuel expense increased 11.1 percent in 2004 primarily due to a 30.5 percent increase in the average price of natural gas and a 3.1 percent increase in the average price of coal.Fuel expense increased 10.1 percent in 2003 due to a 58.3 percent increase in the average price of natural gas and a 2.2 percent increase in the average price of coal.7 V MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report Purchased power consists of purchases from affiliates in the Southern Company electric system and non-affiliated companies.

Purchased power transactions among the Company and its affiliates will vary from period to period depending on demand and the availability and variable production cost of generating resources at each company. Purchased power from non-affiliates increased

$2.5 million (1.0 percent) in 2005. This was due to a 14.3 percent increase in purchased power prices over the previous year. In 2004, purchased power from non-affiliates increased

$75 million (68 percent) due to a 71.7 percent increase in energy purchased offset by a 1.9 percent decrease in purchased power prices compared to 2003. In 2003, purchased power from non-affiliates increased

$20 million (22 percent) due to a 19.3 percent increase in price and a 9.5 percent increase in energy purchased when compared to 2002.A significant upward trend in the cost of coal and natural gas has emerged since 2003, and volatility in these markets is expected to continue.

Increased coal prices have been influenced by a worldwide increase in demand as a result of rapid economic growth in China as well as by increases in mining costs. Higher natural gas prices in the United States are the result of increased demand and slightly lower gas supplies despite increased drilling activity.

Natural gas supply interruptions, such as those caused by the 2004 and 2005 hurricanes, result in an immediate market response; however, the long-term impact of this price volatility may be reduced by imports of natural gas and liquefied natural gas. Fuel expenses, including purchased power, are offset by fuel revenues through the Company's energy cost recovery clause and generally have no effect on net income. The Company continuously monitors the under/over recovered balance and files for a revised fuel rate when management deems appropriate.

See Future Earnings Potential

-"PSC Matters-Retail Fuel Cost Recovery" herein and Note 3 to the financial statements under "Retail Regulatory Matters -Fuel Cost Recovery" for additional information.

Other Expenses Depreciation and amortization expense increased 0.1 percent in 2005, 3.1 percent in 2004, and 3.6 percent in 2003. These increases reflect additions to property, plant, and equipment.

amount of construction work in progress over the prior year. AFUDC also increased

$1.4 million (12.8 percent) in 2003 due to an increase in the applicable AFUDC rate. See Note I to the financial statements under "AFUDC" for additional information.

In 2005 interest expense, net of amounts capitalized increased

$3.8 million to $197.4 million due to an increase in average debt outstanding during the year. This reversed the trend of the past two years when refinancing activities resulted in $20.7 million (9.7 percent) and $11.4 million (5.1 percent) decreases in 2004 and 2003, respectively.

Effects of Inflation The Company is subject to rate regulation that is based on the recovery of costs. When historical costs are included, or when inflation exceeds projected costs used, in rate regulation, the effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. The inflation rate has been relatively low in recent years and any adverse effect of inflation on the Company has not been substantial.

Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed in the Company's approved electric rates.FUTURE EARNINGS POTENTIAL General The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in the State of Alabama and to wholesale customers in the Southeast.

Prices for electricity provided by the Company to retail customers are set by the Alabama PSC under cost-based regulatory principles.

Prices for electricity relating to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power are set by the FERC.Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations.

See ACCOUNTING POLICIES -"Application of Critical Accounting Policies and Estimates

-Electric Utility Regulation" herein and Note 3 to the financial statements under "FERC Matters" and "Retail Regulatory Matters" for additional information about these and other regulatory matters.Allowance for equity funds used during construction (AFUDC) increased

$4.1 million (25.6 percent) and $3.5 million (28.2 percent) in 2005 and 2004, respectively, primarily due to increases in the The results of operations for the past three years are not necessarily indicative of future earnings potential.

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, and risks of the Company's primary business of selling electricity.

These factors include the Company's ability to maintain a stable regulatory environment that continues to allow for the recovery of all prudently incurred costs.Future earnings for the electricity business in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the Company's service area.Environmental Matters New Source Review Actions In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against the Company, alleging that the Company had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws with respect to coal-fired generating facilities at the Company's Plants Miller, Barry, and Gorgas. The EPA concurrently issued to the Company a notice of violation relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation.

The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control: technology at the affected units. The Northern District of Georgia granted the Company's motion to dismiss for lack of jurisdiction in Georgia. The EPA refiled its claims against the Company in the U.S. District Court for the Northern District of Alabama. On June 3, 2005, the U.S.District Court for the Northern District of Alabama issued a decision in favor of the Company on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA's allegations.

In accordance with a separate court order, the Company and the EPA are currently participating in mediation with respect to the EPA's claims.The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation.

An adverse outcome in this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties.

This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. A coalition of states and environmental organizations filed petitions for review of these regulations.

On June 24, 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA's December 2002 revisions to its NSR regulations, which included changes to the regulatory exclusions and methods of calculating emissions increases.

However, the court vacated portions of those revisions, including' those addressing the exclusion of certain pollution control projects.

The October 2003 revisions, which clarified the scope of the existing Routine Maintenance, Repair and Replacement exclusion, have been stayed by the Court of Appeals pending its review of the rules. On October 20, 2005, the EPA also published a proposed rule clarifying the test for determining when an emissions increase subject to the NSR requirements has occurred.

The impact of these revisions and proposed rules will depend on adoption of the final rules by the EPA and the State of Alabama's implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.Carbon Dioxide Litigation In July 2004, attorneys general from eight states, each outside of Southern Company's service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies.

A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies' emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance.

Under common law public and private nuisance theories, the plaintiffs seek a judicial, order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in 9 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company's and the other defendants' motions to dismiss these cases. The plaintiffs filed an appeal to the U.S.Court of Appeals for the Second Circuit on October 19, 2005. The ultimate outcome of these matters cannot be determined at this time.Environmental Statutes and Regulations General The Company's operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources.

Applicable statutes include the Clean Air Act;the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act, and the Endangered Species Act.Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions.

Through 2005, the Company had invested approximately

$961 million in capital projects to comply with these requirements, with annual totals of $256 million, $177 million, and $100 million for 2005, 2004, and 2003, respectively.

Over the next decade, the Company expects that capital expenditures to assure compliance with existing and new regulations could exceed an additional

$2.2 billion, including

$285 million, $426 million, and $406 million for 2006, 2007, and 2008, respectively.

Because the Company's compliance strategy is impacted by changes to existing environmental laws and regulations, the cost, availability, and existing inventory of emission allowances, and the Company's fuel mix, the ultimate outcome cannot be determined at this time.Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY

-"Capital Requirements and Contractual Obligations" herein.Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company.New environmental legislation or regulations, or changes to existing statutes or regulations could affect many areas of the Company's operations; however,,the full impact of any such changes cannot be determined at this time.Air Quality Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2005, the Company had spent approximately

$745 million in reducing sulfur dioxide (SO 2) and nitrogen oxide (NOJ)emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been announced and are currently being installed at several plants to further reduce SO 2 and NO, emissions, maintain compliance with existing regulations, and to meet new requirements.

Approximately

$594 million of these expenditures related to reducing NO, emissions pursuant to state and federal requirements in connection with the EPA's one-hour ozone standard and the 1998 regional NO, reduction rules. In 2004, the regional NO. reduction rules were implemented for the northern two-thirds of Alabama. See Note 3 to the financial statements under"Retail Regulatory Matters" for information regarding the Company's recovery of costs associated with environmental laws and regulations.

In 2005, the EPA revoked the one-hour ozone standard and published the final set of rules for implementation of the new, more stringent eight-hour ozone standard.

The area within the Company's service area that has been designated as nonattainment under the eight-hour ozone standard includes Jefferson and Shelby Counties, near Birmingham.

State implementation plans, including new emission control regulations necessary to bring those areas into attainment are required for most areas by June 2007. These state implementation plans could require further reductions in NO, emissions from power plants.In November 2005, the State of Alabama, through the Alabama Department of Environmental Management, submitted a request to the EPA to redesignate the Birmingham eight-hour ozone non-attainment area to attainment for the standard.

On January 25, 2006, the EPA published a proposal in the Federal Register to approve the redesignation request. If ultimately approved by the EPA, the area would be designated to be in attainment.

The final outcome of this matter cannot now be determined.

10 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report During 2005, the EPA's fine particulate matter nonattainment designations became effective for several areas within the Company's service area, and the EPA proposed a rule for the implementation of the fine particulate matter standard.

The EPA plans to finalize the proposed implementation rule in 2006.State plans for addressing the nonattainment designations are required by April 2008 and could require further reductions in SO 2 and NO, emissions from power plants. The EPA has also published proposed revisions to lower the levels of particulate matter currently allowed.The EPA issued the final Clean Air Interstate Rule on March 10, 2005. This cap-and-trade rule addresses SO 2 and NO, emissions from power plants that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including the State of Alabama, are subject to the requirements of the rule. The rule calls for additional reductions of NO, and/or SO 2 to be achieved in two phases, 2009/2010 and 2015. These reductions will be accomplished by the installation of additional emission controls at the Company's coal-fired facilities or by the purchase of emission allowances from a cap-and-trade program.The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized on July 6, 2005.The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) requirements and a review each decade, beginning in 2018, of progress toward the goal. BART requires that sources that contribute to visibility impairment implement additional emission reductions, if necessary, to make progress toward remedying current visibility concerns.

For power plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for S02 and NO,. However, additional requirements could be imposed. By December 17, 2007, states must submit implementation plans that contain emission reduction strategies for implementing BART requirements and for achieving sufficient and reasonable progress toward the goal.On March 15, 2005, the EPA announced the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emissions allowance trading market.The Company anticipates that emission controls installed to achieve compliance with the Clean Air Interstate Rule and the eight-hour ozone and fine-particulate standards will also result in mercury emission reductions.

However, the long-term capability of emission control equipment to reduce mercury emissions is still being evaluated, and the installation of additional control technologies may be required.The impacts of the eight-hour ozone standard, the fine particulate matter designations, the Clean Air Interstate Rule, the Clean Air Visibility Rule, and the Clean Air Mercury Rule on the Company will depend on the development and implementation of rules at the state level. States implementing the Clean Air Mercury Rule and the Clean Air Interstate Rule, in particular, have the option not to participate in the national cap-and-trade programs and could require reductions greater than those mandated by the federal rules. Such impacts will also depend on resolution of pending legal challenges to the Clean Air Interstate Rule, the Clean Air Mercury Rule, and a related petition from the State of North Carolina under Section 126 of the Clean Air Act, also related to the interstate transport of air pollutants.

Therefore, the full impacts of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO 2 , NO,, and mercury emission controls within the next several years to assure continued compliance with applicable air quality requirements.

Water Quality In July 2004, the EPA published final rules under the Clean Water Act for the purpose of reducing impingement and entrainment of fish and fish larvae at power plants' cooling water intake structures.

The new rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants.The full impact of these new rules will depend on the results of studies and analyses performed as part of the rules' implementation and the actual requirements established by state regulatory agencies, and therefore, cannot now be determined.

11 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report Environmental Remediation The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and release of hazardous substances.

Under these various laws and regulations, the Company could incur substantial costs to clean up properties.

The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites.Amounts for cleanup and ongoing monitoring costs were not material for any year presented.

The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation.

Global Climate Issues Domestic efforts to limit greenhouse gas emissions have been spurred by international discussions surrounding the Framework Convention on Climate Change, and specifically the Kyoto Protocol, which proposes constraints on the emissions of greenhouse gases for a group of industrialized countries.

The Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation; however, in 2002, it did announce a goal to reduce the greenhouse gas intensity of the U.S., the ratio of greenhouse gas emissions to the value of U.S. economic output, by 18 percent by 2012. A year later, the Department of Energy (DOE) announced the Climate VISION program to support this goal.Energy-intensive industries, including electricity generation, are the initial focus of this program.Southern Company is involved in the development of a voluntary electric utility sector climate change initiative in partnership with the government.

In a memorandum of understanding signed in December 2004 with the DOE under Climate VISION, the utility sector pledged to reduce its greenhouse gas emissions rate by 3 percent to 5 percent by 2010 -2012. The Company is continuing to evaluate future energy and emission profiles relative to the Climate VISION program and is analyzing voluntary programs to support the industry initiative.

FERC Matters Market-Based Rate A uthority The Company has authorization from the FERC to sell power to non-affiliates at market-based prices. The Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

In December 2004, the FERC initiated a proceeding to assess Southern Company's generation dominance within its retail service territory.

The ability to charge market-based rates in other markets is not an issue in that proceeding.

In February 2005, Southern Company submitted responsive information.

In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions.

Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding.

The impact of such sales to the Company through December 31, 2005 is not expected to exceed $3.6 million. The refund period covers 15 months. In the event that the FERC's default mitigation measures for entities that are found to have market power are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC's market-based rate analysis:

transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation.

Any and all new market-based rate transactions both inside and outside Southern Company's retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales to the Company through December 31, 2005, is not expected to exceed $8.9 million, of which $2.6 million relates to sales inside the retail service territory discussed above. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below.The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, 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 determined.

Intercompany Interchange Contract The Company's generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC's standards of conduct applicable to utility companies that are transmission providers, and (3)whether Southern Company's code of conduct defining Southern Power as a "system company" rather than a"marketing affiliate" is just and reasonable.

In connection with the formation of Southern Power, the FERC authorized Southern Power's inclusion in the IIC in 2000.The FERC also previously approved Southern Company's code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power, Georgia Power, and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate.

Hearings are scheduled for September 2006. Effective July 19,2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Generation Interconnection Agreements In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider.

The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements.

Subsidiaries of Tenaska, Inc., as counterparties to two previously executed interconnection agreements with the Company, have filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $11 million previously paid for interconnection facilities, with interest.

These proceedings are still pending at the FERC. The Company has also received similar requests from other entities totaling approximately

$7 million. The Company has opposed all such requests.The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.Transmission In December 1999, the FERC issued its final rule on Regional Transmission Organizations (RTOs). Since that time, there have been a number of additional proceedings at the FERC designed to encourage further voluntary formation of RTOs or to mandate their formation.

However, at the current time, there are no active proceedings that would require the Company to participate in an RTO. Current FERC efforts that may potentially change the regulatory and/or operational structure of transmission include rules related to the standardization of generation interconnection, as well as an inquiry into, among other things, market power by vertically integrated utilities.

See "Market-Based Rate Authority" and "Generation Interconnection Agreements" herein for additional information.

The final outcome of these proceedings cannot now be determined.

However, the Company's financial condition, results of operations and cash flows could be adversely affected by future changes in the federal regulatory or operational structure of transmission.

Hydro Relicensing In July 2005, the Company filed two applications with the FERC for new 50-year licenses for the Company's seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin)and for the Lewis Smith and Bankhead developments on the Warrior River. The FERC licenses for all of these nine projects expire in 2007.In 2006, the Company will initiate the process of developing a relicensing application for the Martin hydroelectric project located on the Tallapoosa River.The current Martin license will expire in 2013.13 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report Upon or after the expiration of each license, the United States Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee.

The FERC may grant relicenses subject to certain requirements that could result in additional costs to the Company. The final outcome of these matters cannot be determined at this time.Nuclear Relicensing The Company filed an application with the Nuclear Regulatory Commission (NRC) in September 2003 to extend the operating license for Plant Farley for an additional 20 years. In May 2005, the NRC granted the Company a 20-year extension of the operating license for both units at Plant Farley. As a result of the license extension, amounts previously contributed to the external trust are currently projected to be adequate to meet the decommissioning obligations.

Therefore, in June 2005, the Alabama PSC approved the Company's request to suspend, effective January 1, 2005, the inclusion in its annual cost of service of $18 million in decommissioning costs and to also suspend the associated obligation to make semi-annual contributions to the external trust. See Note 1 to the financial statements under "Nuclear Decommissioning" for additional information.

PSC Matters Retail Rate Adjustments In October 2005, the Alabama PSC approved a revision to Rate RSE requested by the Company. Effective January 2007, Rate RSE adjustments will be based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4 percent per year and any annual adjustment is limited to 5 percent. Rates remain unchanged when the return on common equity ranges between 13.0 percent and 14.5 percent. If the Company's actual retail return on common equity is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return on common equity fall below the allowed equity return range. The Company will make its initial submission of projected data for calendar year 2007 by December 1, 2006. See Note 3 to the financial statements under "Retail Regulatory Matters -Rate RSE" for further information.

The Company's retail rates, approved by the Alabama PSC, also provide for adjustments to recognize the placing of new generating facilities into retail service and the recovery of retail costs associated with certificated PPAs under Rate Certificated New Plant (CNP). In October 2004, the Alabama PSC amended Rate CNP to also allow for the recovery of the Company's retail costs associated with environmental laws, regulations, or other such mandates.

The rate mechanism began operation in January 2005 and provides for the recovery of these costs pursuant to a factor that is calculated annually.

Environmental costs to be recovered include operation and maintenance expenses, depreciation, and a return on invested capital.Retail rates increased approximately 1.0 percent in January 2005 and 1.2 percent in January 2006. It is currently anticipated that retail rates will increase approximately 0.5 percent in 2007. In conjunction with the Alabama PSC's approval of this rate mechanism, the Company agreed to a moratorium through 2006 on retail rate increases under Rate RSE.Effective July 2003, the Company's retail rates were adjusted by approximately 2.6 percent under Rate CNP as a result of two new certificated PPAs that began in June 2003. An additional increase of 0.8 percent in retail rates, or $25 million annually, was effective July 2004 under Rate CNP for new certificated PPAs. In April 2005, an adjustment to Rate CNP decreased retail rates by approximately 0.5 percent, or $19 million annually.

The projected annual true-up adjustment to be effective in April 2006 is expected to increase retail rates by 0.5 percent, or $19 million annually.

See Note 3 to the financial statements under "Retail Regulatory Matters -Rate CNP" for additional information.

Retail Fuel Cost Recovery The Company has established fuel cost recovery rates approved by the Alabama PSC. As a result of increased fuel costs for coal and gas, the Company filed a fuel cost recovery increase under the provisions of its energy cost recovery rate (Rate ECR). In December 2005, the Alabama PSC approved an increase of the energy billing factor for retail customers from 1.788 cents per KWH to 2.400 cents per KWH, effective with billings beginning January 2006. This change to the billing factor represents on average an increase of approximately

$6.12 per month for a customer billing of 1,000 KWHs. This approved increase was intended to allow for the recovery of energy 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 associated with the under recovered fuel costs in the fuel expense calculation.

As a result of the order, the Company reclassified

$186.9 million of the under-recovered regulatory clause revenues from current assets to deferred charges and other assets in the balance sheet as of December 31, 2005. See Note 3 to the financial statements under "Retail Regulatory Matters -Fuel Cost Recovery" for additional information.

Rate ECR revenues, as recorded on the financial statements, are adjusted for the difference in actual recoverable costs and amounts billed in current regulated rates. Accordingly, this approved increase in the billing factor will have no significant effect on the Company's revenues or net income, but will increase annual cash flow.Natural Disaster Cost Recovery The Company maintains a reserve for operation and maintenance expense to cover the cost of damages from major storms to its transmission and distribution facilities.

On July 10, 2005 and August 29, 2005, Hurricanes Dennis and Katrina, respectively, hit the coast of Alabama and continued north through the state, causing significant damage in parts of the service territory of the Company.Approximately 241,000 and 637,000 of the Company's 1.4 million customer accounts were without electrical service immediately after Hurricanes Dennis and Katrina, respectively.

The Company sustained significant damage to its distribution and transmission facilities during these storms.In August 2005, the Company received approval from the Alabama PSC to defer the Hurricane Dennis storm-related operation and maintenance costs (approximately

$28 million), which resulted in a negative balance in the!natural disaster reserve (NDR). In October 2005, the Company also received similar approval from the Alabama PSC to defer the Hurricane Katrina storm-related operation and maintenance costs (approximately

$30 million).

See Note 1 and Note 3 to the financial statements under "Natural Disaster Reserve" and "Natural Disaster Cost Recovery," respectively, for additional information on these reserves.

The natural disaster reserve deficit balance at December 31, 2005 was $50.6 million.In December 2005, the Alabama PSC approved a request by the Company to replenish the depleted NDR and allow for recovery of future natural disaster costs. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of uninsured storm damage exceed any established reserve balance. The order also approved a separate monthly NDR charge consisting of two components beginning January 2006. The first component is intended to establish and maintain a target reserve balance of $75 million for future storms and is an on-going part of customer billing. The Company currently expects that the target reserve balance could be achieved within five years.The second component of the NDR charge is intended to allow recovery of the existing deferred hurricane related operation and maintenance costs and any future reserve deficits over a 24-month period. The maximum total NDR charge consisting of both components is $ 10 per month per non-residential customer account and $5 per month per residential customer account.As revenue from the NDR charge is recognized, an equal amount of operation and maintenance expense related to the NDR will also be recognized.

As a result, this increase in revenue and expense will not have an impact on net income but will increase the annual cash flow.Other Matters In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash pre-tax pension income of approximately

$21 million, $36 million, and$52 million in 2005, 2004, and 2003, respectively.

Postretirement benefit costs for the Company were $28 million, $22 million, and $23 million in 2005, 2004, and 2003, respectively.

Both pension and postretirement benefit costs are expected to trend upward. Such amounts are dependent on several factors including trust earnings and changes to the plans. A portion of pension and postretirement benefit costs is capitalized based on construction-related labor charges. Pension and postretirement benefit costs are a component of the regulated rates and generally do not have a long-term effect on net income. For more information regarding pension and postretirement benefits, see Note 2 to the financial statements.

The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings.

See Note 3 to the financial statements for information regarding material issues.15 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report ACCOUNTING POLICIES Application of Critical Accounting Policies and Estimates The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note I to the financial statements.

In the application of these policies, certain estimates are made that may have a material impact on the Company's results of operations and related disclosures.

Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements.

Management has reviewed and discussed critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.

Electric Utility Regulation The Company is subject to retail regulation by the Alabama PSC and wholesale regulation by the FERC.These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation (Statement No. 71), which requires the financial statements to reflect the effects of rate regulation.

Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities.

The application of Statement No. 71 has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on the Company's results of operations than they would on a non-regulated company.As reflected in Note I to the financial statements under "Regulatory Assets and Liabilities," significant regulatory assets and liabilities have been recorded.Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines and accounting principles generally accepted in the United States.However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements.

Contingent Obligations The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject it to environmental, litigation, income tax, and other risks. See "FUTURE EARNINGS POTENTIAL" herein and Note 3 to the financial statements for more information regarding certain of these contingencies.

The Company periodically evaluates its exposure to such risks and records reserves for those matters where a loss is considered probable and reasonably estimable in accordance with generally accepted accounting principles.

The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company's financial statements.

These events or conditions include the following:

• Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances, hazardous and solid wastes, and other environmental matters.* Changes in existing income tax regulations or changes in Internal Revenue Service interpretations of existing regulations.

• Identification of additional sites that require environmental remediation or the filing of other complaints in which the Company may be asserted to be a potentially responsible party.* Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant.

• 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 Revenues related to the sale of electricity are recorded when electricity is delivered to customers.

However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated.

Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage.These components can fluctuate as a result of a number of factors including weather, generation patterns, power delivery volume, and other operational constraints.

These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company's results of operations.

New Accounting Standards Income Taxes In December 2004, the FASB issued FASB Staff Position 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (FSP 109-1), which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction.

The Company adopted FSP 109-1 in the first quarter of 2005 with no material impact on its financial statements.

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

$35 million. The adoption of FIN 47 did not have any effect on the Company's income statement.

Stock Options On January 1, 2006, the Company adopted FASB Statement No. 123R, Share-Based Payment, on a modified prospective basis. This statement requires that compensation cost relating to share-based payment transactions be recognized in financial statements.

That cost will be measured based on the grant date fair value of the equity or liability instruments issued. Although the compensation expense required under the revised statement differs slightly, the impacts on the Company's financial statements are similar to the pro forma disclosures included in Note 1 to the financial statements under "Stock Options." FINANCIAL CONDITION AND LIQUIDITY Overview The Company's financial condition continued to be strong at December 31, 2005. Net cash flow from operating activities totaled $0.9 billion, $1.0 billion, and$ 1.1 billion for 2005, 2004, and 2003, respectively.

The$106 million decrease for 2005 in operating activities primarily relates to an increase in under recovered fuel cost and storm damage costs related to Hurricanes Dennis and Katrina. These increases were partially offset by the deferral of income tax liabilities arising from accelerated depreciation deductions.

The $104 million decrease from 2003 to 2004 resulted from under recovered fuel cost and storm damage costs related to Hurricane Ivan partially offset by accelerated depreciation reductions.

Fuel and storm damage costs are recoverable in future periods.Under recovered fuel cost is included in the balance sheets as under recovered regulatory clause revenue and deferred under recovered regulatory clause revenues.

Under recovered storm damage cost is included in the balance sheets as other current assets and other regulatory assets.See FUTURE EARNINGS POTENTIAL

-"Fuel Cost Recovery" and "Natural Disaster Cost Recovery" herein for additional information.

Significant balance sheet changes for 2005 include an increase of $668 million in gross plant. In 2004 significant balance sheet changes included the $478 million increase in long-term debt primarily due to the replacement of debt due within one year with long-term debt, and an increase of $408 million in gross plant.17 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report The Company's ratio of common equity to total capitalization

-- including short-term debt -- was 42.2 percent in 2005, 42.6 percent in 2004, and 43.3 percent in 2003. See Note 6 to the financial statements for additional information.

The Company has received investment grade ratings from the major rating agencies.Sources of Capital The Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows. In recent years, the Company has primarily utilized unsecured debt, preferred stock, and preferred securities.

However, the type and timing of any financings

-- if needed -- will depend on market conditions and regulatory approval.Security issuances are subject to regulatory approval by the Alabama PSC. Additionally, with respect to the public offering of securities, the Company must file registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the Alabama PSC, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.The Company obtains financing separately without credit support from any affiliate.

See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.

The Southern Company system does not maintain a centralized cash or money pool.Therefore, funds of the Company are not commingled with funds of any other company.The Company's current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt as well as cash needs which can fluctuate significantly due to the seasonality of the business.To meet short-term cash needs and contingencies, the Company has various internal and external sources of liquidity.

At the beginning of 2006, the Company had approximately

$22 million of cash and cash equivalents and$878 million of unused credit arrangements with banks, as described below. In addition, the Company has substantial cash flow from operating activities and access to the capital markets, including commercial paper programs, to meet liquidity needs.The Company maintains committed lines of credit in the amount of $878 million, of which $428 million will expire at various times during 2006. $251 million of the credit facilities expiring in 2006 allow for the execution of term loans for an additional one-year period. -See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.

The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other Southern Company retail operating companies.

Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other retail operating company. The obligations of each company under these arrangements are several and there is no cross affiliate credit support.As of December 31, 2005 the Company had $136 million in commercial paper outstanding, $55 million in extendible commercial notes outstanding, and $125 million in loans outstanding under an uncommitted credit arrangement.

As of December 31, 2004, the Company had no extendible commercial notes and no commercial paper outstanding.

Financing Activities During 2005, the Company issued $250 million of long-term debt. In addition, the Company issued one million new shares of common stock to Southern Company at$40.00 a share and realized proceeds of $40 million. The proceeds of these issues were used to repay short-term indebtedness, and for other general corporate purposes.

In November 2005, the Company incurred obligations in connection with the issuance of $21.5 million of variable rate pollution control bonds. The proceeds were used to refund $21.5 million 5.50% fixed rate pollution control bonds.In January and February 2006, the Company issued$600 million of long-term debt. The proceeds of these issues were used to repay short-term indebtedness and for other general corporate purposes.

In conjunction with these transactions, the Company terminated

$600 million notional amount of interest rate swaps at a gain of $18 million. The gain will be amortized to interest expense over a 10-year period.18

.MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report Credit Rating Risk The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

However, the Company is party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price risk management activities.

At December 31, 2005, the Company's exposure to these agreements was not material.Market Price Risk Due to cost-based rate regulations, the Company has limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity.

To manage the volatility attributable to these exposures, the Company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices.

Company policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies.

Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.To mitigate future exposure to changes in interest rates, the Company has entered into forward starting interest rate swaps that have been designated as hedges.The weighted average interest rate on $271.5 million of long-term variable interest rate exposure that has not been hedged at January 1, 2006 was 4.45 percent. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately

$2.7 million at January 1, 2006. The Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term.For further information, see Notes 1 and 6 to the financial statements under "Financial Instruments." To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into similar contracts for gas purchases.

The Company has implemented fuel hedging programs at the instruction of the Alabama PSC.In addition, the Company's Rate ECR allows the recovery of specific costs associated with the sales of natural gas that become necessary due to operating considerations at the Company's electric generating facilities.

Rate ECR also allows recovery of the cost of financial instruments used for hedging market price risk up to 75 percent of the budgeted annual amount of natural gas purchases.

The Company may not engage in natural gas hedging activities that extend beyond a rolling 42-month window. Also, the premiums paid for natural gas financial options may not exceed 5 percent of the Company's natural gas budget for that year.At December 31, 2005, exposure from these activities was not material to the Company's financial position, results of operations, or cash flows. The changes in fair value of energy related derivative contracts and year-end valuations were as follows at December 3 1: Changes in Fair Value 2005 2004 (in thousands)

Contracts beginning of year $ 4,017 $ 6,413 Contracts realized or settled (38,320) (26,384)New contracts at inception

--Changes in valuation techniques Current period changes(a) 63,281 23,988 Contracts end of year $ 28,978 $ 4,017 (a) Current period changes also include the changes in fair value of new contracts entered into during the period.Source of 2005 Year-End_ Valuation Prices Total Maturity Fair Value 2006 2007-2008 (in thousands)

Actively quoted $29,177 $19,392 $9,785 External sources (199) (199) -Models and other methods -Contracts end of Year $28,978 $19,193 $9,785 Unrealized gains and losses from mark-to-market adjustments on derivative contracts related to the Company's fuel hedging programs are recorded as regulatory assets and liabilities.

Realized gains and losses from these programs are included in fuel expense and are recovered through the Company's fuel cost recovery clause. Gains and losses on derivative contracts that are not designated as hedges are recognized in the income statement as incurred.

At December 31, 2005, the fair 19 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report value of derivative energy contracts was reflected in the financial statements as follows: Amounts (in thousands)

Regulatory liabilities, net $29,044 Other comprehensive income Net income (66)Total fair value $28,978 Unrealized pre-tax gains (losses) on energy contracts recognized in income were not material for any year presented.

The Company is exposed to market price risk in the event of nonperformance by counterparties to the derivative energy contracts.

The Company's policy is to enter into agreements with counterparties that have investment grade credit ratings by Moody's and Standard& Poor's or with counterparties who have posted collateral to cover potential credit exposure.

Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties.

For additional information, see Notes 1 and 6 to the financial statements under "Financial Instruments." Capital Requirements and Contractual Obligations The construction program of the Company is currently estimated to be $0.9 billion for 2006, $ 1.1 billion for 2007, and $ 1.1 billion for 2008. Environmental 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.In addition to the funds required for the Company's construction program, approximately

$1.6 billion will be required by the end of 2008 for maturities of long-term debt. The Company plans to continue, when economically feasible, to retire higher cost securities and replace these obligations with lower-cost capital if market conditions permit.As discussed in Note I to the financial statements under "Nuclear Fuel Disposal Costs," in 1993 the DOE implemented a special assessment over a 15-year period on utilities with nuclear plants to be used for the decontamination and decommissioning of its nuclear fuel enrichment facilities.

The final installment is scheduled to occur in 2006.The Company has also established an external trust fund for postretirement benefits as ordered by the Alabama PSC. The cumulative effect of funding these items over a long period will diminish internally funded capital for other purposes and may require the Company to seek capital from other sources. For additional information, see Note 2 to the financial statements under"Postretirement Benefits." Other funding requirements related to obligations associated with scheduled maturities of long-term debt and preferred securities, as well as the related interest, preferred stock dividends, leases, and other purchase commitments, are as follows. See Notes 1, 6, and 7 to the financial statements for additional information.

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 in the statements of capitalization.

Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk.(b) For additional information, see Notes 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 (This page intentionally left blank)

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 Current Liabilities:

Securities due within one year Notes payable Accounts payable --Affiliated Other Customer deposits Accrued taxes --Income taxes Other Accrued interest Accrued vacation pay Accrued compensation Other Total current liabilities Long-term Debt (See accompanying statements)

Long-term Debt Payable to Affiliated Trusts (See accompanying statements)

Deferred Credits and Other Liabilities:

Accumulated deferred income taxes Deferred credits related to income taxes Accumulated deferred investment tax credits Employee benefit obligations Asset retirement obligations Other cost of removal obligations Other regulatory liabilities Other Total deferred credits and other liabilities Total Liabilities Cumulative Preferred Stock (See accompanying statements)

Common Stockholder's Equity (See accompanying statements)

Total Liabilities and Stockholder's Equitv Commitments and Contingent Matters (See notes)The accompanying notes are an integral part of these financial statements.

2005 2004 (in thousands)

$ 546,645 $ 225,005 315,278 190,744 141,096 266,174 198,834 56,709 47,664 63,844 28,498 31,692 29,688 46,018 40,029 37,646 36,494 92,784 76,858 72,991 34,289 1,720,525 3,560,186 309,279 858,455 3,855,257 309,279 2,070,746 101,678 196,585 208,663 446,268 600,104 194,135 23,966 3,842,145 9,432,135 465,046 3,792,726$13.689.907 1,885,120 148,395 205,353 194,837 383,621 597,147 206,765 62,045 3,683,283 8,706,274 465,047 3,610,204$12,781,525 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 2.65% to 2.80% due 2006 Floating rate (1.94% at 1/1/06) due 2006 3.50% to 7.125% due 2007 Floating rate (2.14% at 1/1/06) due 2007 3.125% to 5.375% due 2008 Floating rate (4.58% at 1/1/06) due 2009 4.70% due 2010 5.125% to 5.875% due 2011-2035 Total long-term notes payable C l-520,000 26,500 500,000 168,500 410,000 250,000 100,000 1,575,000$3,550,000

$ 225,000 520,000 195,000 500,000 410,000 250,000 100,000 1,325,000$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 POLICIES General Alabama Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of five retail operating companies, Southern Power Company (Southern Power), Southern Company Services (SCS), Southern Communications Services (SouthernLINC Wireless), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries.

The retail operating companies

-- the Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company -- provide electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast.

Southern Power constructs, owns, and manages Southern Company's competitive generation assets and sells electricity at market-based rates in the wholesale market.Contracts among the retail operating companies and Southern Power -- related to jointly-owned generating facilities, interconnecting transmission lines, or the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC). SCS -- the system service company -- provides, at cost, specialized services to Southern Company and its subsidiary companies.

SouthernLINC Wireless provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast.

Southern Telecom provides fiber cable services within the Southeast.

Southern Holdings is an intermediate holding subsidiary for Southern Company's investments in synthetic fuels and leveraged leases and various other energy-related businesses.

Southern Nuclear operates and provides services to Southern Company's nuclear power plants, including the Company's Plant Farley. On January 4, 2006, Southern Company completed the sale of substantially all the assets of Southern Company Gas, its competitive retail natural gas marketing subsidiary.

The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable interest entities where the Company is not the primary beneficiary.

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

SoutherntCompany was registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA), until its repeal on February 8, 2006. Both Southern Company and its subsidiaries, including the Company, were subject to the regulatory provisions of the PUHCA. The Company is subject to regulation by the FERC and the Alabama Public Service Commission (PSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by its regulatory commissions.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from those estimates.

Affiliate Transactions The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, purchasing, accounting and statistical analysis, finance and treasury, tax, information resources, marketing, auditing, insurance and pension administration, human resources, systems and procedures, and other services with respect to business and operations and power pool transactions.

Costs for these services amounted to $246 million, $224 million, and $217 million during 2005, 2004, and 2003, respectively.

Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission (SEC) prior to the repeal of PUHCA, and management believes they are reasonable.

The Company has an agreement with Southern Nuclear under which Southern Nuclear operates the Company's Plant Farley and provides the following nuclear-related services at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, statistical analysis, employee relations, and other services with respect to business and operations.

Costs for these services amounted to $157 million, $169 million, and $153 million during 2005, 2004, and 2003, respectively.

The Company jointly owns Plant Greene County with Mississippi Power. The Company has an agreement with Mississippi Power under which the Company operates Plant Greene County, and Mississippi Power reimburses the Company for its proportionate share of expenses which were $8.2 million in 2005, $7.2 million in 2004, and $6.6 million in 2003. See Note 4 for additional information.

30 NOTES (continued)

Alabama Power Company 2005 Annual Report Southern Company holds a 30 percent ownership interest in Alabama Fuel Products, LLC (AFP), which produces synthetic fuel. The Company has an agreement with an indirect subsidiary of Southern Company that provides services for AFP. Under this agreement, the Company provides certain accounting functions, including processing and paying fuel transportation invoices, and the Company is reimbursed for its expenses.

Amounts billed under this agreement totaled approximately

$31.5 million,$28.7 million, and $27.5 million in 2005, 2004 and 2003, respectively.

In addition, the Company purchases synthetic fuel from AFP for use at several of the Company's plants. Fuel purchases for 2005, 2004, and 2003 totaled $265.7 million, $236.9 million, and $209.2 million, respectively.

In June 2003, the Company entered into an agreement with Southern Power under which the Company operates and maintains Plant Harris at cost. In 2005, 2004 and 2003, the Company billed Southern Power $1.9 million,$1.8 million and $0.8 million, respectively, for operation and maintenance.

Under a power purchase agreement (PPA) with Southern Power, the Company's purchased power costs from Plant Harris in 2005, 2004 and 2003 totaled $63.6 million, $59.0 million and $41.7 million, respectively.

The Company also provides the fuel, at cost, associated with the PPA and the fuel cost recognized by the Company in 2005 was $81.3 million, $65.7 million in 2004, and $33.9 million in 2003. Additionally, the Company recorded $8.3 million of prepaid capacity expenses included in other deferred charges and other assets in the balance sheets at December 31, 2005 and 2004. See Note 3 under "Retail Regulatory Matters" and Note 7 under "Purchased Power Commitments" for additional information.

The Company has an agreement with SouthermLINC Wireless to provide digital wireless communications services to the Company. Costs for these services amounted to $5.7 million, $5.3 million, and $4.9 million during 2005, 2004, and 2003, respectively.

Also, see Note 4 for information regarding the Company's ownership in and PPA with Southern Electric Generating Company (SEGCO) and Note 5 for information on certain deferred tax liabilities due to affiliates.

Mississippi Power in the last two years, assistance provided to aid in storm restoration, including company labor, contract labor, and materials, has caused an increase in these activities.

The total amount of storm restoration provided to Georgia Power and Gulf Power in 2004 and to Mississippi Power in 2005 was $2.4 million, $2.3 million and $8.0 million, respectively.

In 2004 and 2005, the Company received assistance from affiliated companies in the amount of $5.6 million and $5.0 million, respectively, for aid in major storm restoration.

These activities were billed at cost.The retail operating companies, including the Company, and Southern Power jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements.

See Note 7 under "Fuel Commitments" for additional information.

Revenues Energy and other revenues are recognized as services are provided.

Capacity revenues are generally recognized on a levelized basis over the appropriate contract periods.Unbilled revenues are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company continuously monitors the under/over recovered balance and files for a revised fuel rate when management deems appropriate.

See "Retail Regulatory Matters -Fuel Cost Recovery" in Note 3 for additional information.

The Company has a diversified base of customers.

No single customer or industry comprises 10 percent or more of revenues.

For all periods presented, uncollectible accounts averaged less than one percent of revenues.Fuel Costs The Company provides incidental services to, and receives such services from, other Southern Company subsidiaries which are generally minor in duration and/or amount. However, with the hurricane damage experienced by Georgia Power, Gulf Power and Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emission allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear 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, and $64 million in 2003.Regulatory Assets and Liabilities The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation.

Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2005 2004 Note (in millions)Deferred income tax charges $ 389 $ 317 (a)Loss on reacquired debt 102 109 (b)DOE assessments 5 9 (c)Vacation pay 38 36 (d)Rate CNP under recovery 31 18 (e)Natural disaster reserve 51 38 (e)Fuel-hedging assets 9 6 (f)Other assets 13 13 (e)Asset retirement obligations (139) (159) (a)Other cost of removal obligations (600) (597) (a)Deferred income tax credits (102) (148) (a)Deferred purchased power (19) (19) (e)Mine reclamation and remediation (16) (25) (e)Fuel-hedging liabilities (38) (10) (f)Other liabilities (11) (1) (e)Total $(287) $(413)Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Asset retirement and removal liabilities are recorded, deferred income tax assets are recovered, and deferred tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.(b) Recovered over the remaining life of the original issue which may range up to 50 years.(c) Assessments for the decontamination and decommissioning of the DOE nuclear fuel enrichment facilities are recorded annually from 1993 through 2006.(d) Recorded as earned by employees and recovered as paid, generally within one year.(e) Recorded and recovered or amortized as approved by the Alabama PSC.(f) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clauses.In the event that a portion of the Company's operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are currently reflected in rates.Nuclear Fuel Disposal Costs The Company has a contract with the U.S. Department of Energy (DOE) that provides for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contract, and the Company is pursuing legal remedies against the government for breach of contract.

Construction of an on-site dry spent fuel storage facility at Plant Farley was completed in 2005 and can be expanded to accommodate spent fuel through the life of the plant.Also, the Energy Policy Act of 1992 established a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants. This assessment has been paid over a 15 year period; the final installment is scheduled to occur in 2006. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities.

The law provides that utilities will recover these payments in the same manner as any other fuel expense. The Company estimates its remaining liability at December 31, 2005 under this law to be approximately

$5 million.Income Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences.

Investment tax credits utilized are deferred and amortized to income over the average life of the related property.Property, Plant, and Equipment Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments.

Original cost includes:

materials; labor; minor items of property;appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits;and the interest capitalized and/or cost of funds used during construction.

32 NOTES (continued)

Alabama Power Company 2005 Annual Report The Company's property, plant, and equipment consisted of the following at December 31 (in millions):

Generation Transmission Distribution General Plant acquisition adjustment Total nlant in service 2005 2004$ 7,971 $ 7,635 2,205 2,097 4,115 3,922 1,000 969 9 9$15,300 $14.632-The cost of replacements of property -- exclusive of minor items of property -- is capitalized.

The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific Alabama PSC orders. The Company accrues estimated refueling costs in advance of the unit's next refueling outage. The refueling cycle is 18 months for each unit. During 2005, the Company accrued $28 million and paid $19.7 million for an outage at Unit 2. At December 31, 2005, the reserve balance totaled $7.5 million and is included in the balance sheet in other regulatory liabilities.

Depreciation and Amortization Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.9 percent in 2005, 3.0 percent in 2004, and 3.1 percent in 2003.Depreciation studies are conducted periodically to update the composite rates and the information is provided to the Alabama PSC. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation.

Minor items of property included in the original cost of the plant are retired when the related property unit is retired.Asset Retirement Obligations and Other Costs of Removal Effective January 1, 2003, the Company adopted FASB Statement No. 143, Accounting for Asset Retirement Obligations, which established new accounting and reporting standards for legal obligations associated with the ultimate costs of retiring long-lived assets. The 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 useful life. In addition, effective December 31, 2005, the Company adopted the provisions of FASB Interpretation No. 47, Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events.Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers because the timing of their retirements was dependent on future events. The Company has received accounting guidance from the Alabama PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations will continue to be reflected in the balance sheets as a regulatory liability.

Therefore, the Company had no cumulative effect to net income resulting from the adoption of Statement No.143 or Interpretation No. 47.The liability recognized to retire long-lived assets primarily relates to the Company's nuclear facility, Plant Farley. The fair value of assets legally restricted for settling retirement obligations related to nuclear facilities as of December 31, 2005 was $467 million.See "Nuclear Decommissioning" herein for further information.

In addition, the Company recognized asset retirement obligations related to various landfill sites and underground storage tanks. In connection with the adoption of Interpretation No. 47, the Company recognized additional asset retirement obligations (and assets) of $35 million, related to asbestos removal and disposal of polychlorinated biphenyls in certain transformers.

The Company has also identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated.

The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment.

Any difference between costs recognized under Statement No. 143 and Interpretation No. 47 and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Alabama PSC, and are reflected in the balance sheets.33 NOTES (continued)

Alabama Power Company 2005 Annual Report Details of the asset retirement obligations included in the balance sheets are as follows: Balance beginning of year Liabilities incurred Liabilities settled Accretion Cash flow revisions Balance end of year 2005 2004 (in millions)$384 $359 36 -26 25$446 $384-If Interpretation No. 47 had been adopted as of December 31, 2004, the pro forma asset retirement obligations would have been $417 million.Nuclear Decommissioning The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning.

The Company has external trust funds to comply with the NRC's regulations.

Use of the funds is restricted to nuclear decommissioning activities and the funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the Alabama PSC, as well as the Internal Revenue Service (IRS). The trust funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are classified as available-for-sale.

The trust funds are included in the balance sheets at fair value, as obtained from quoted market prices for the same or similar investments.

Details of the securities held in these trusts at December 31 are as follows: Unrealized Unrealized 2005 Gains Losses Fair Value (in millions)Equity $78.9 $(7.7) $275.3 Debt 1.3 (1.6) 106.1 Other 17.0 -85.6 Total $97.2 $(9.3) $467.0 Unrealized Unrealized 2004 Gains Losses Fair Value (in millions)Equity $71.3 $(4.3) $258.1 Debt 3.2 (0.6) 95.5 Other 13.6 (0.2) 92.0 Total $88.1 $(5.1) $445.6 Sales of the securities held in the trust funds resulted in proceeds of $223.8 million, $249.0 million, and $330.0 million in 2005, 2004, and 2003, respectively, all of which were re-invested.

Net realized gains (losses) were $9.9 million, $7.5 million and $(1.7) million in 2005, 2004, and 2003, respectively.

Realized gains and losses are determined on a specific identification basis. In accordance with regulatory guidance, all realized and unrealized gains and losses are included in the regulatory liability for Asset Retirement Obligations in the balance sheets and are not included in net income or other comprehensive income. Unrealized gains and losses are considered non-cash transactions for purposes of the statements of cash flow. Unrealized losses were not material in any period presented and do not represent any impairment of the underlying investments.

The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC. At December 31, 2005, the accumulated provisions for decommissioning were as follows: (in millions)External trust funds, at fair value $467 Internal reserves 28 Total $495 Site study cost is the estimate to decommission the facility as of the site study year. The estimated costs of decommissioning, based on the most current study performed in 2003 for Plant Farley were as follows: Decommissioning periods: Beginning year Completion year 2017 2046 (in millions)Site study costs: Radiated structures

$892 Non-radiated structures 63 Total $955 The contractual maturities of debt securities at December 31, 2005 are as follows: $14.1 million in 2006; $55.2 million in 2007-2010;

$27.1 million in 2011-2015; and $8.3 million thereafter.

The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.

34 NOTES (continued)

Alabama Power Company 2005 Annual Report All of the Company's decommissioning costs for ratemaking are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5 percent and a trust earnings rate of 7.0 percent. Another significant assumption used was the change in the operating license for Plant Farley.In May 2005, the NRC granted the Company a 20-year extension of the operating license for both units at Plant Farley. As a result of the license extension, amounts previously contributed to the external trust are currently projected to be adequate to meet the decommissioning obligations.

Therefore, in June 2005, the Alabama PSC approved the Company's request to suspend, effective January 1, 2005, the inclusion in its annual cost of service of $18 million in decommissioning costs and to also suspend the associated obligation to make semi-annual contributions to the external trust. The Company will continue to provide site specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with the NRC and other applicable requirements.

The approved suspension does not affect the transfer of internal reserves (less than $1 million annually) previously collected from customers prior to the establishment of the external trust.Allowance for Funds Used During Construction (AFUDC)In accordance with regulatory treatment, the Company records AFUDC. AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities.

While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. All current construction costs are included in retail rates. The composite rate used to determine the amount of AFUDC was 8.8 percent in 2005, 8.6 percent in 2004, and 9.0 percent in 2003. AFUDC, net of income tax, as a percent of net income after dividends on preferred stock was 5.0 percent in 2005, 4.2 percent in 2004, and 3.5 percent in 2003.Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.

The determination of whether impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment provision is required.

Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.Natural Disaster Reserve In accordance with an Alabama PSC order, the Company has established a natural disaster reserve (NDR) to cover the cost of uninsured damages from major storms to transmission and distribution facilities.

The Company may collect a monthly NDR charge per account that consists of two components beginning January 1, 2006.The first component is intended to establish and maintain a reserve for future storms and is an on-going part of customer billing. This plan has a target reserve balance of$75 million that could be achieved in five years. The second component of the NDR charge is intended to allow recovery of the deferred Hurricanes Dennis- and Katrina-related operation and maintenance costs and to set in place a mechanism to replenish the natural disaster reserve should any future storms deplete the natural disaster reserve. The Alabama PSC order gives the Company authority to have a negative NDR balance when costs of uninsured storm damage exceed any established NDR balance. This second component allows for the recovery of a negative balance over a 24-month period. The maximum total NDR charge consisting of both components is $ 10 per month per account for non-residential customers and $5 per month per account for residential customers.

As revenue from the natural disaster reserve charge is recognized, an equal amount of operation and maintenance expense related to the natural disaster reserve will also be recognized.

As a result, this increase in revenue and expense will not have an impact on net income, but will increase the annual cash flow.Environmental Cost Recovery The Company has received authority from the Alabama PSC to recover approved environmental compliance costs through specific retail rate clauses. Within limits approved by the Alabama PSC, these rates are adjusted 35 NOTES (continued)

Alabama Power Company 2005 Annual Report annually.

See Note 3 under "Retail Regulatory Matters -Rate Adjustment Procedures" for additional information.

Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents.

Temporary cash investments are securities with original maturities of 90 days or less.Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials.

Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

Fuel Inventory Fuel inventory includes the average costs of oil, coal, and natural gas. Fuel is charged to inventory when purchased and then expensed as used. Emission allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.Stock Options Southern Company provides non-qualified stock options to a large segment of the Company's employees ranging from line management to executives.

The Company accounts for its stock-based compensation plans in accordance with Accounting Principles Board Opinion No. 25. Accordingly, no compensation expense has been recognized because the exercise price of all options granted equaled the fair-market value of Southern Company's common stock on the date of grant. When options are exercised, the Company receives a capital contribution from Southern Company equivalent to the related income tax benefit.For pro forma purposes, Southern Company generally recognizes stock option expense on a straight-line basis over the vesting period. Stock options granted to 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 The estimated fair values of stock options granted in 2005, 2004, and 2003 were derived using the Black-Scholes stock option pricing model. The following table shows the assumptions and the weighted average fair values of stock options: 2005 2004 2003 Interest rate 3.9% 3.1% 2.7%Average expected life of stock options (in years) 5.0 5.0 4.3 Expected volatility of common stock 17.9% 19.6% 23.6%Expected annual dividends on common stock $1.43 $1.40 $1.37 Weighted average fair value of stock options granted $3.90 $3.29 $3.59 Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales.All derivative financial instruments are recognized as either assets or liabilities and are measured at fair value.Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are exempt from fair value accounting requirements and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the Alabama PSC approved fuel-hedging program. This results in the deferral of related gains and losses in other comprehensive income or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income.The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance.

The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.36 NOTES (continued)

Alabama Power Company 2005 Annual Report The Company's other financial instruments for which the carrying amount did not equal fair value at December 31 were as follows: Carrying Fair Amount Value (in millions)Long-term debt: 2005 2004$4,416 $4,403 4,389 4,454 The fair values were based on either closing market price or closing price of comparable instruments.

Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners.Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, and changes in additional minimum pension liability, less income taxes and reclassifications for amounts included in-net income.Variable Interest Entities The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities.

The Company has established certain wholly-owned trusts to issue preferred securities.

See Note 6 under"Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts" for additional information.

However, the Company is not the primary beneficiary of the trusts. Therefore, the investments in these trusts are reflected as Other Investments, and the related loans from the trusts are reflected as Long-term Debt Payable to Affiliated Trusts in the balance sheets.See Note 6 under "Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts" for additional information.

Investments The Company maintains an investment in a debt security that matures in 2018 and is classified as available-for-sale.

This security is included in the balance sheets under Other Property and Investments-Other and totaled $4.4 million and $4.8 million at December 31, 2005 and 2004, respectively.

Because the interest rate resets weekly, the carrying value approximates the fair market value.2. RETIREMENT BENEFITS The Company has a defined benefit, trusteed, pension plan covering substantially all employees.

The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In 2005, the plan was amended to provide an additional monthly supplement to certain retirees.

No contributions to the plan are expected for the year ending December 31, 2006. The Company also provides certain non-qualified benefit plans for a selected group of management and highly-compensated employees.

Benefits under these non-qualified plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees.

The Company funds trusts to the extent required by the Alabama PSC. For the year ended December 31, 2006, postretirement trust contributions are expected to total approximately

$24.9 million.The measurement date for plan assets and obligations is September 30 for each year.Pension Plans The accumulated benefit obligation for the pension plans was $1.3 billion in 2005 and $1.2 billion in 2004. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows: Projected Benefit Obligations 2005 2004 (in millions)Balance at beginning of year $1,325 $1,200 Service cost 33 30 Interest cost 74 71 Benefits paid (65) (64)Plan amendments 8 1 Actuarial (gain) loss 46 87 Balance at end of year $1,421 $1,325 Plan Assets 2005 2004 (in millions)Balance at beginning of year $1,676 $1,583 Actual return on plan assets 262 157 Employer contributions 4 4 Benefits paid (67) (68)Balance at end of year $1,875 $1,676 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 accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company's investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below.Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.Plan Assets Target 2005 2004 Domestic equity 36% 40% 36%International equity 24 24 20 Fixed income 15 17 26 Real estate 15 13 10 Private equity 10 6 8 Total 100% 100% 100%The reconciliations of the funded status with the accrued pension costs recognized in the balance sheets were as follows: 2005 2004 (in millions)Funded status $454 $351 Unrecognized prior service cost 79 80 Unrecognized net (gain) loss (52) 27 Prepaid pension asset, net $481 $458 Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligations for the pension plans. At December 31, 2005, estimated benefit payments were as follows: 2006 2007 2008 2009 2010 2011 to 2015 Benefit Payments (in millions)$ 65.2 66.6 68.4 70.6 73.6$429.2 Postretirement Benefits Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows: Accumulated Benefit Obligations 2005 2004 The prepaid pension asset, net is reflected in the balance sheets in the following line items: 2005 2004 (in millions)Prepaid pension asset $515 $489 Employee benefit obligations (67) (60)Intangible asset 10 10 Accumulated other comprehensive income 23 19 Prepaid pension asset, net $481 $458 (in millions)Balance at beginning of year $465 $441 Service cost 7 7 Interest cost 26 24 Benefits paid (21) (18)Actuarial (gain) loss 13 11 Balance at end of year $490 $465 Plan Assets 2005 2004 (in millions)Balance at beginning of year $212 $186 Actual return on plan assets 28 24 Employer contributions 26 20 Benefits paid (21) (18)Balance at end of year $245 $212 Components of the pension plans' net periodic cost were as follows: 2005 2004 2003 (in millions)Service cost $ 33 $ 30 $ 27 Interest cost 74 71 68 Expected return on plan assets (139) (138) (138)Recognized net (gain) loss 2 (3) (12)Net amortization 9 4 3 Net pension cost (income) $ (21) $ (36) $ (52)Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Company's investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below.Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.38 NOTES (continued)

Alabama Power Company 2005 Annual Report Plan Assets Target 2005 2004 Domestic equity 49% 53% 46%International equity 11 11 13 Fixed income 29 28 33 Real estate 7 6 5 Private equity 4 2 3 Total 100% 100% 100%Benefit Subsidy Payments Receipts Total (in millions)2006 $ 24.5 $ (2.6) $ 21.9 2007 25.6 (3.1) 22.5 2008 27.8 (3.5) 24.3 2009 30.4 (3.8) 26.6 2010 32.9 (4.1) 28.8 2011 to 2015 $180.2 $(27.7) $152.5 The accrued postretirement costs recognized in the balance sheets were as follows: Actuarial Assumptions Funded status Unrecognized transition obligation Unrecognized prior service cost Unrecognized net loss (gain)Fourth quarter contributions Accrued liability recognized in the balance sheets 2005 2004 (in millions)$(245) $(253)29 33 64 68 85 87 12 9$ (55) $ (56)The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations and the net periodic costs for the pension and postretirement benefit plans were as follows: 2005 2004 2003 Discount 5.50% 5.75% 6.00%Annual salary increase 3.00 3.50 3.75 Long-term return on plan assets 8.50 8.50 8.50 The Company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.Components of the postretirement plans' net periodic cost were as follows: 2005 2004 2003 (in millions)Service cost $ 7 $ 7 $ 6 Interest cost 26 24 25 Expected return on plan assets (16) (18) (17)Net amortization 11 9 9 Net postretirement cost $ 28 $ 22 $ 23 In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees.

FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plans. The effect of the subsidy reduced the Company's expenses for the six months ended December 31, 2004 and for the year ended December 31, 2005 by approximately

$3.2 million and $8.7 million, respectively, and is expected to have a similar impact on future expenses.Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the accumulated 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: i I An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 10.25 percent for 2005, decreasing gradually to 4.75 percent through the year 2014, and remaining at that level thereafter.

An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2005 as follows: I Percent 1 Percent Increase Decrease (in millions)Benefit obligation

$40 $35 Service and interest costs 3 2 Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees.

The Company provides a 75 percent matching contribution up to 6 percent of an employee's base salary. Total matching contributions made to the plan for 2005, 2004, and 2003 were $14 million, $13 million, and $12 million, respectively.

39 NOTES (continued)

Alabama Power Company 2005 Annual Report 3. CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters The Company is subject to certain claims and legal actions arising in the ordinary course of business.

In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment.

Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements such as opacity and other air quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent.

The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on the Company's financial statements.

Environmental Matters New Source Review Actions In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against the Company, alleging that the Company had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws with respect to coal-fired generating facilities at the Company's Plants Miller, Barry, and Gorgas. The EPA concurrently issued to the Company a notice of violation relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation.

The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The Northern District of Georgia granted the Company's motion to dismiss for lack of jurisdiction in Georgia. The EPA refiled its claims against the Company in the U.S. District Court for the Northern District of Alabama. On June 3, 2005, the U.S.District Court for the Northern District of Alabama issued a decision in favor of the Company on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA's allegations.

In accordance with a separate court order, the Company and the EPA are currently 40 participating in mediation with respect to the EPA's claims.The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation.

An adverse outcome in this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties.

This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.FERC Matters Market-Based Rate Authority The Company has authorization from the FERC to sell power to nonaffiliates at market-based prices. The Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

In December 2004, the FERC initiated a proceeding to assess Southern Company's generation dominance within its retail service territory.

The ability to charge market-based rates in other markets is not an issue in that proceeding.

In February 2005, Southern Company submitted responsive information.

In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions.

Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding.

The impact of such sales to the Company through December 31, 2005 is not expected to exceed $3.6 million. The refund period covers 15 months. In the event that the FERC's default mitigation measures for entities that are found to have market power are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

NOTES (continued)

Alabama Power Company 2005 Annual Report In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC's market-based rate analysis:

transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation.

Any and all new market-based rate transactions both inside and outside Southern Company's retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales to the Company through December 31, 2005, is not expected to exceed $8.9 million, of which $2.6 million relates to sales inside the retail service territory discussed above. The 15-month refund period will end on October 19, 2006. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the Intercompany Interchange Contract (TIC) discussed below.The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Intercompany Interchange Contract The Company's generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC's standards of conduct applicable to utility companies that are transmission providers, and (3)whether Southern Company's code of conduct defining Southern Power as a "system company" rather than a"marketing affiliate" is just and reasonable.

In connection with the formation of Southern Power, the FERC authorized Southern Power's inclusion in the IIC in 2000.The FERC also previously approved Southern Company's code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power, Georgia Power, and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate.

Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries are subject to refund to the extent the FERC orders any changes to the IIC.The Company believes that there is no meritorious basis for these allegations and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Generation Interconnection Agreements In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider.

The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements.

Subsidiaries of Tenaska, Inc., as counterparties to two previously executed interconnection agreements with the Company, have filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $ 11 million previously paid for interconnection facilities, with interest.

These proceedings are still pending at the FERC.The Company has also received similar requests from other entities totaling approximately

$7 million. The Company has opposed all such requests.

The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.Retail Regulatory Matters The following retail ratemaking procedures will remain in effect until the Alabama PSC votes to modify or discontinue them.Rate RSE The Alabama PSC has adopted a Rate Stabilization and Equalization plan (Rate RSE) that provides for periodic annual adjustments based upon the Company's earned return on end-of-period retail common equity. Prior to January 2007, annual adjustments are limited to 3 percent.Rates remain unchanged when the return on common 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 RSE adjustments are made based on forward-looking information for the applicable upcoming calendar year.Rate adjustments for any two-year period, when averaged together, cannot exceed 4.0 percent per year and any annual adjustment is limited to 5.0 percent. The range of return on common equity, on which such adjustments are based, remains unchanged.

If the Company's actual return on common equity is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual return on common equity fall below the allowed equity return range. The Company will make its initial submission of projected data for calendar year 2007 by December 1, 2006. In conjunction with the Alabama PSC approval of a rate mechanism to recover retail costs associated with environmental laws and regulations in October 2004, the Company agreed to a moratorium on retail rate increases under Rate RSE through 2006. See"Rate CNP" herein for additional information.

Rate CNP The Alabama PSC has also approved a rate mechanism that provides for adjustments to recognize the placing of new generating facilities in retail service and for the recovery of retail costs associated with certificated purchased power agreements (Rate CNP). In October 2004, the Alabama PSC approved a request by the Company to amend Rate CNP to provide for the recovery of retail costs associated with environmental laws and regulations.

Environmental costs to be recovered include operation and maintenance expenses, depreciation and a return on invested capital. This component of Rate CNP began operation in January 2005.To recover certificated purchased power costs under Rate CNP, increases of 2.6 percent in retail rates, or $79 million annually were effective July 2003 and 0.8 percent in retail rates, or $25 million annually were effective July 2004 for certificated purchase power cost. In April 2005, an adjustment to Rate CNP decreased retail rates by approximately 0.5 percent, or $19 million annually.

In April 2006, an annual true-up adjustment to Rate CNP is expected to increase retail rates by approximately 0.5 percent, or $19 million annually.The retail rates associated with the recovery of retail costs associated with environmental laws and regulations under Rate CNP are adjusted annually in January. Retail rates increased approximately 1.0 percent in 2005, or $33 million and approximately 1.2 percent in 2006, or $43 million.Fuel Cost Recovery The Company has established fuel cost recovery rates approved by the Alabama PSC. The Company can change the retail energy cost recovery rate after submitting to the Alabama PSC an estimate of future energy costs and the current over or under recovered balance. In response to such a request, the Alabama PSC may conduct a public hearing prior to its ruling. Alternatively, the retail energy cost recovery rates requested by the Company will become effective 45 days after the initial request.In December 2005, the Alabama PSC approved the Company's request to increase the retail energy cost recovery rate to 2.400 cents per kilowatt-hour, effective with billings beginning January 1, 2006.Natural Disaster Cost Recovery In September 2004, Hurricane Ivan hit the Gulf Coast of Florida and Alabama and continued north through the Company's service territory causing substantial damage.The related costs charged to the Company's NDR were$57.8 million. During 2004, the Company accrued $9.9 million to the reserve and at December 31, 2004, the reserve balance was a regulatory asset of $37.7 million.In February and December 2005, the Company requested and received Alabama PSC approval of an accounting order that allowed the Company to immediately return certain regulatory liabilities to the retail customers.

These orders also allowed the Company to simultaneously recover from customers an accrual of approximately

$48 million to primarily offset the costs of Hurricane Ivan and restore a positive balance in the natural disaster reserve. The combined effects of these orders had no impact on the Company's net income in 2005.On July 10, 2005 and August 29, 2005, Hurricanes Dennis and Katrina, respectively, hit the coast of Alabama and continued north through the state, causing significant damage in parts of the service territory of the Company.Approximately 241,000 and 637,000 of the Company's 1.4 million customer accounts were without electrical service immediately after Hurricanes Dennis and Katrina, respectively.

The Company sustained significant damage 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 the Alabama PSC to defer the Hurricane Dennis storm-related operation and maintenance costs (approximately

$28 million).

In October 2005, the Company also received similar approval from the Alabama PSC to defer the Hurricane Katrina storm-related operation and maintenance costs (approximately

$30 million).

The NDR balance at December 31, 2005 was a regulatory asset of$50.6 million.In December 2005, the Alabama PSC approved a request by the Company to replenish the depleted NDR and allow for recovery of future natural disaster costs. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of uninsured storm damage exceed any established reserve balance. The order also approved a separate monthly NDR charge consisting of two components beginning January 2006. The first component is intended to establish and maintain a target reserve balance of $75 million for future storms and is an on-going part of customer billing. The Company currently expects that the target reserve balance could be achieved within five years.The second component of the NDR charge is intended to allow recovery of the existing deferred hurricane related operation and maintenance costs and any future reserve deficits over a 24 month period. The maximum total NDR charge consisting of both components is $ 10 per month per non-residential customer account and $5 per month per residential customer account.As revenue from the NDR charge is recognized, an equal amount of operation and maintenance expense related to the NDR will also be recognized.

As a result, this increase in revenue and expense will not have an impact on net income, but will increase the annual cash flow.4. JOINT OWNERSHIP AGREEMENTS The Company and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 megawatts, as well as associated transmission facilities.

The capacity of these units is sold equally to the Company and Georgia Power under a contract which, in substance, requires payments sufficient to provide for the operating expenses, taxes, interest expense and a return on equity, whether or not SEGCO has any capacity and energy available.

The term of the contract extends automatically for two-year periods, subject to either party's right to cancel upon two year's notice. The Company's share of purchased power totaled $90 million in 2005, $86 million in 2004, and $87 million in 2003 and is included in"Purchased power from affiliates" in the statements of income. The Company accounts for SEGCO using the equity method.In addition, the Company has guaranteed unconditionally the obligation of SEGCO under an installment sale agreement for the purchase of certain pollution control facilities at SEGCO's generating units, pursuant to which $24.5 million principal amount of pollution control revenue bonds are outstanding.

Also, the Company has guaranteed

$50 million principal amount of unsecured senior notes issued by SEGCO for general corporate purposes.

Georgia Power has agreed to reimburse the Company for the pro rata portion of such obligations corresponding to its then proportionate ownership of stock of SEGCO if the Company is called upon to make such payment under its guaranty.At December 31, 2005, the capitalization of SEGCO consisted of $60 million of equity and $89 million of debt on which the annual interest requirement is $3.2 million.SEGCO paid dividends totaling $7.7 million in 2005, $12.0 million in 2004, and $2.3 million in 2003, of which one-half of each was paid to the Company. In addition, the Company recognizes 50 percent of SEGCO's net income.In addition to the Company's ownership of SEGCO, the Company's percentage ownership and investment in jointly-owned coal-fired generating plants at December 31, 2005 is as follows: Total Megawatt Company Facility (Type) Capacity Ownership Greene County 500 60.00% (1)Plant Miller Units I and 2 1,320 91.84% (2)(1) Jointly owned with an affiliate, Mississippi Power.(2) Jointly owned with Alabama Electric Cooperative, Inc.Company Accumulated Facility Investment Depreciation (in millions)Greene County $115 $ 60 Plant Miller Units 1 and 2 940 374 At December 31, 2005, the Company's Plant Miller portion of construction work in progress was $4.4 million.43 NOTES (continued)

Alabama Power Company 2005 Annual Report The Company has contracted to operate and maintain the jointly owned facilities as agent for their co-owners.

The Company's proportionate share of its plant operating expenses is included in operating expenses in the statements of income.5. INCOME TAXES Southern Company files a consolidated federal income tax return and combined income tax returns for the State of Georgia and the State of Alabama. Under a joint consolidated income tax allocation agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if they filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability.

Details of the income tax provisions are as follows: 2005 2004 (in millions)2003 Federal --Current Deferred$151 81 232$ 44 219 263$111 137 248 State --Current Deferred 27 26 53$285 16 34 50$313 26 16 42$290 Total The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: In 2004, in order to avoid the loss of certain federal income tax credits related to the production of synthetic fuel, Southern Company chose to defer certain deductions otherwise available to the subsidiaries.

The cash flow benefit associated with the utilization of the tax credits was allocated to the subsidiary that otherwise would have claimed the available deductions on a separate company basis without the deferral.

This allocation concurrently reduced the tax benefit of the credits allocated to those subsidiaries that generated the credits. As the deferred expenses are deducted, the benefit of the tax credits will be repaid to the subsidiaries that generated the tax credits.At December 31,2005 and 2004, the Company had $20.4 million and $21.4 million in accumulated deferred income taxes and $2.0 million and $2.3 million in accrued taxes -income taxes, respectively, payable to these subsidiaries, on the balance sheets.At December 31, 2005, the Company's tax-related regulatory assets and liabilities were $389 million and$102 million, respectively.

These assets are attributable to tax benefits flowed through to customers in prior years, to taxes applicable to capitalized interest, and to deferred taxes previously recognized at rates different than the current enacted tax law. These liabilities are primarily attributable to unamortized investment tax credits.2005 2004 (in millions)Deferred tax liabilities:

Accelerated depreciation Property basis differences Premium on reacquired debt Pensions Fuel clause under recovered Storm reserve Other$1,626 440 42 148 138 26 46 2,466$ 1,524 416 45 136 48 20 36 2,225 Total Deferred tax assets: Federal effect of state deferred taxes State effect of federal deferred taxes Unbilled revenue Pension and other benefits Other comprehensive losses Other Total Total deferred tax liabilities, net Portion included in current (liabilities) assets, net Accumulated deferred income taxes in the balance sheets 114 87 22 20 19 69 331 112 110 22 16 16 36 312 2,135 1,913 (64) (28)$2,071 $1,885 ,-- ; , In accordance with regulatory requirements, deferred 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 to the effective income tax rate is as follow 2005 2 Federal statutory rate 35.0%State income tax, net of federal deduction 4.2 Non-deductible book depreciation 1.1 Differences in prior years'deferred and current tax rates (4.1)Other (1.3)Effective income tax rate 34.9%y income tax rate contract, the Company received payments from AMEA is: representing the net present value of the revenues 004 2003 associated with the capacity entitlement, discounted at an 35.0% 35.0% effective annual rate of 11.19 percent. These payments were recognized as operating revenues and the discount-4.0 3.5 was amortized to other interest expense as scheduled capacity was made available over the terms of the 1.1 1.2 contract.(0.8)(1.0)38.3%(0.9)(1.6)37.2%In accordance with Alabama PSC orders, the Company returned approximately

$30 million of excess deferred income taxes to its ratepayers in 2005, resulting in causing 3.6 percent of the "Difference in prior years'deferred and current tax rates" in the table above. See Note 3 to the financial statements under "Retail Regulatory Matters -Natural Disaster Cost Recovery" for additional information.

To secure AMEA's advance payments and the Company's performance obligation under the contracts, the Company issued and delivered to an escrow agent first mortgage bonds representing the maximum amount of liquidated damages payable by the Company in the event of a default under the contracts.

No principal or interest was payable on such bonds unless and until a default by the Company occurred.

As the liquidated damages declined, a portion of the bond equal to the decrease was returned to the Company. At December 31, 2005, the bonds that were previously held in escrow were returned to the Company due to the fulfillment of the contract obligation.

Pollution Control Bonds 6. FINANCING Mandatorily Redeemable Preferred Securities/

Long-Term Debt Payable to Affiliated Trusts The Company has formed certain wholly owned trust subsidiaries for the purpose of issuing preferred securities.

The proceeds of the related equity investments and preferred security sales were loaned back to the Company through the issuance of junior subordinated notes totaling$309 million, which constitute substantially all assets of these trusts and are reflected in the balance sheets as Long-term Debt Payable to Affiliated Trusts. The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective trusts' payment obligations with respect to these securities.

At December 31, 2005, preferred securities of $300 million were outstanding.

See Note I under "Variable Interest Entities" for additional information on the accounting treatment for these trusts and the related securities.

First Mortgage Bonds The Company had a firm power sales contract with the Alabama Municipal Electric Authority (AMEA) entitling AMEA to scheduled amounts of capacity (up to a maximum 80 megawatts).

Under the terms of the Pollution control obligations represent installment purchases of pollution control facilities financed by funds derived from sales by public authorities of revenue bonds.The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. With respect to $92.8 million of such pollution control obligations, the Company has authenticated and delivered to the trustees a like principal amount of first mortgage bonds as security for its obligations under the installment purchase agreements.

No principal or interest on these first mortgage bonds is payable unless and until a default occurs on the installment purchase agreements.

Senior Notes The Company issued a total of $250 million of unsecured senior notes in 2005. The proceeds of these issues were used to repay short-term indebtedness, and for other general corporate purposes.At December 31, 2005 and 2004, the Company had$3.6 billion and $3.5 billion of senior notes outstanding, respectively.

These senior notes are subordinate to all secured debt of the Company which amounted to approximately

$246 million at December 31, 2005.45 NOTES (continued)

Alabama Power Company 2005 Annual Report Securities Due Within One Year At December 31, 2005 and 2004, the Company had scheduled maturities and redemptions of senior notes due within one year totaling $547 million and $225 million respectively.

Debt serial maturities through 2010 applicable to total long-term debt are as follows: $547 million in 2006; $669 million in 2007; $410 million in 2008; $250 million in 2009; and $100 million in 2010.Assets Subject to Lien The Company's mortgage, as amended and supplemented, securing the first mortgage bonds issued by the Company, constitutes a direct lien on substantially all of the Company's fixed property and franchises.

Bank Credit Arrangements The Company maintains committed lines of credit in the amount of $878 million (including

$563 million of such lines which are dedicated to funding purchase obligations relating to variable rate pollution control bonds), of which$428 million will expire at various times during 2006.$251 million of the credit facilities expiring in 2006 allow for the execution of one-year term loans. All of the credit arrangements require payment of a commitment fee based on the unused portion of the commitment or the maintenance of compensating balances with the banks.Commitment fees are less than 1/4 of I percent for the Company. Because the arrangements are based on an average balance, the Company does not consider any of its cash balances to be restricted as of any specific date. For syndicated credit arrangements, a fee is also paid to the agent banks.Most of the Company's credit arrangements with banks have covenants that limit the Company's debt to 65 percent of total capitalization, as defined in the arrangements.

For purposes of calculating these covenants, long-term notes payable to affiliated trusts are excluded from debt but included in capitalization.

Exceeding this debt level would result in a default under the credit arrangements.

At December 31, 2005, the Company was in compliance with the debt limit covenants.

In addition, the credit arrangements typically contain cross default provisions that would be triggered if the Company defaulted on other indebtedness (including guarantee obligations) above a specified threshold.

None of the arrangements contain material adverse change clauses at the time of borrowings.

The Company borrows through commercial paper programs that have the liquidity support of committed bank credit arrangements.

In addition, the Company borrows from time to time through extendible commercial note programs and uncommitted credit arrangements.

As of December 31, 2005, the Company had $136 million in commercial paper outstanding, $55 million in extendible commercial notes outstanding, and $125 million in loans outstanding under an uncommitted credit arrangement.

As of December 31, 2004, the Company had no extendible commercial notes and no commercial paper outstanding.

During 2005, the peak amount outstanding for short-term borrowings was $315 million and the average amount outstanding was $31 million. The average annual interest rate on short-term borrowings in 2005 was 4.04 percent.Short-term borrowings are included in notes payable in the balance sheets.At December 31, 2005, the Company had regulatory approval to have outstanding up to $1.4 billion of short-term borrowings.

Financial Instruments The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity.

The Company has implemented fuel-hedging programs at the instruction of the Alabama PSC. The Company also enters into hedges of forward electricity sales.There was no material ineffectiveness recorded in earnings in 2005, 2004, and 2003.At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows: Regulatory liabilities, net Net income Total fair value Amounts (in thousands)

$29,044 (66)$28,978 The fair value gain or loss for hedges that are recoverable through the regulatory fuel clauses are recorded in the regulatory assets and liabilities and are recognized in earnings at the same time the hedged items affect earnings.

The Company has energy-related hedges in place up to and including 2008.The Company also enters into derivatives to hedge exposure to changes in interest rates. Derivatives 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 the derivatives employed as hedging instruments are generally structured to match the critical terms of the hedged debt instruments, no material ineffectiveness has been recorded in earnings.At December 31, 2005, the Company had$1.3 billion notional amount of interest rate swaps outstanding with net fair value gains of $25.3 million as follows: Weighted Average Maturity Fixed Rate Paid 1.89 2.01*4.82 4.42 Fair Value Notional Gain/Amount (Loss)(in millions)$195 $2.5 536 7.3 300 3.0 300 12.5 2006 2007 2016 2016*Hedged using the Bond Market Association Municipal Swap Index.The fair value gain or loss for cash flow hedges is recorded in other comprehensive income and is reclassified into earnings at the same time the hedged items affect earnings.

In 2005,2004, and 2003, the Company settled gains (losses) of $(21.4) million, $5.5 million and $(8.0) million, respectively, upon termination of certain interest derivatives at the same time it issued debt. These gains (losses) have been deferred in other comprehensive income and will be amortized to interest expense over the life of the original interest derivative, which approximates to the underlying related debt.For the years 2005, 2004 and 2003, approximately

$3.5 million, $(6.3) million, and $(11.3) million, respectively, of pre-tax gains/(losses) were reclassified from other comprehensive income to interest expense.For 2006, pre-tax gains of approximately

$9.4 million are expected to be reclassified from other comprehensive income to interest expense. The Company has interest-related hedges in place through 2016 and has gains/losses that are being amortized through 2035.7. COMMITMENTS Construction Program The Company is engaged in continuous construction programs, currently estimated to total $0.9 billion in 2006, $1.1 billion in 2007, and $1.1 billion in 2008.These amounts include $18 million, $11 million, and'$9 million in 2006, 2007, and 2008, respectively, for construction expenditures related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included under "Fuel Commitments" herein. The construction programs are subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors.These factors include: changes in business conditions; revised load growth estimates; changes in environmental regulations; changes in existing nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2005, significant purchase commitments were outstanding in connection with the construction program. The Company has no generating plants under construction.

Construction of new transmission and distribution facilities and capital improvements, including those needed to meet environmental standards for existing generation, transmission, and distribution facilities, will continue.Long-Term Service Agreements The Company has entered into several Long-Term Service Agreements (LTSAs) with General Electric (GE) for the purpose of securing maintenance support for its combined cycle and combustion turbine generating facilities.

The LTSAs provide that GE will perform all planned inspections on the covered equipment, which includes the cost of all labor and materials.

GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in each contract.In general, these LTSAs are in effect through two major inspection cycles per unit. Scheduled payments to GE are made at various intervals based on actual operating hours of the respective units. Total payments to GE under these agreements for facilities owned are currently estimated at $263 million over the term of the agreements, which are approximately 12 to 14 years per unit. At December 31, 2005, the remaining balance was approximately

$181 million. However, the LTSAs contain various cancellation provisions at the option of the Company.Payments made to GE prior to the performance of any planned maintenance are recorded as either prepayments or other deferred charges and assets in the balance sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed.

I 47 NOTES (continued)

Alabama Power Company 2005 Annual Report Purchased Power Commitments The Company has entered into various long-term commitments for the purchase of electricity.

Total estimated minimum long-term obligations at December 31, 2005 were as follows: Affiliate Year 2006 2007 2008 1 2009 2010 l 2011 and thereafter Total commitments

$ SO 50 50 50 12$212 Commitments Non-d Affiliated (in millions)$ 37 38 39 40 23 2$179 Total$ 87 88 89 190 35 2$391 Company GAS may be jointly and severally liable. The creditworthiness of Southern Power and Southern Company GAS is currently inferior to the creditworthiness of the retail operating companies.

Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other retail operating companies to insure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power or Southern Company GAS as a contracting party under these agreements.

Operating Leases The Company has entered into rental agreements for coal rail cars, vehicles, and other equipment with various terms and expiration dates. These expenses totaled $27.3 million in 2005, $28.3 million in 2004, and $29.5 million in 2003. Of these amounts, $17.8 million, $16.3 million, and $19.4 million for 2005, 2004, and 2003, respectively, relates to the rail car leases and are recoverable through the Company's Rate ECR. At December 31, 2005, estimated minimum rental commitments for noncancellable operating leases were as follows: Fuel Commitments To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments.

Natural gas purchase commitments contain given volumes with prices based on various indices at the time of delivery.

Amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2005.Total estimated minimum long-term commitments at December 31, 2005 were as follows: Rail Vehicles Year Cars & Other Total (in millions)2006 $16.2 $7.4 $23.6 2007 8.9 6.1 15.0 2008 8.6 4.9 13.5 2009 4.8 4.6 9.4 2010 3.5 4.1 7.6 201 1 and thereafter 24.0 5.1 29.1 Total minimum paments $66.0 $32.2 $98.2 Natural Gas Nuclear Fuel Year 2006 2007 2008 2009 2010 2011 and thereafter Total commitments

$ 545 269 145 26 19 89$1,093 Coal (in millions)$1,065 1,027 524 442 422 324$3,804$18 11 9 3 6 26$73 Additional commitments for fuel will be required to supply the Company's future needs.SCS may enter into various types of wholesale energy 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 Company GAS. Under these agreements, each of the retail operating companies, Southern Power, and Southern In addition to the rental commitments above, the Company has potential obligations upon expiration of certain leases with respect to the residual value of the leased property.

These leases expire in 2006 and 2009, and the Company's maximum obligations are $66 million and $20 million, respectively.

At the termination of the leases, at the Company's option, the Company may negotiate an extension, exercise its purchase option, or the property can be sold to a third party. The Company expects that the fair market value of the leased property would substantially eliminate the Company's payments under the residual value obligations.

Guarantees 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 discussed in Note 4, and to certain residual values of leased assets as described above in "Operating Leases." 8. STOCK OPTION PLAN Southern Company provides non-qualified stock options to a large segment of the Company's employees ranging from line management to executives.

As of December 31, 2005, 1,106 current and former employees of the Company participated in this stock option plan. The maximum number of shares of 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 granted to date become exercisable pro rata over a maximum period of three years from the date of grant.Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. Activity from 2003 to 2005 for the options granted to the Company's employees under the stock option plan is summarized below: The following table summarizes information about options outstanding at December 31, 2005: Dollar Price Range of Options 13-21 21-28 28-35 Outstanding:

Shares (in thousands) 700 2,266 2,262 Average remaining life (in years) 4.3 6.3 8.6 Average exercise price $17.30 $26.05 $31.17 Exercisable:

Shares (in thousands) 700 1,897 346 Average exercise price $17.30 $25.68 $29.59 Balance at December 31, 2002 Options granted Options canceled Options exercised Balance at December 31, 2003 Options granted Options canceled Options exercised Balance at December 31, 2004 Options granted Options canceled Options exercised Balance at December 31, 2005 Shares Subject to Option 5,693,923 1,201,469 (6,726)(1,043,013) 5,845,653 1,168,140 (3,379)(1,252,277) 5,758,137 1,180,491 (1,973)(1,708,670) 5,227,985...I I Average Option Price per Share$19.72 27.98 23.11 16.16 22.05 29.50 28.82 18.07 24.42 32.70 30.10 21.95$27.09 9. NUCLEAR INSURANCE Under the Price-Anderson Amendment Act (Act), the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Farley. The Act provides funds up to$10.8 billion for public liability claims that could arise from a single nuclear incident.

Plant Farley is insured against this liability to a maximum of $300 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors.

The Company could be assessed up to $ 101 million per incident for each licensed reactor it operates but not more than an aggregate of $15 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company is$201 million per incident but not more than an aggregate of $30 million to be paid for each incident in any one year.The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to$500 million for members' nuclear generating facilities.

Additionally, the Company has policies that currently 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.---. 1- __-._...._._

__.. -_11 I 11INUIMILor, I I. U LHULUdl 11INUICL CMUMINIMU LU Options exercisable:

At December 31, 2003 3,171,383 At December 31, 2004 3,404,264 At December 31, 2005 2,943,134 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.After this deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years.The Company purchases the maximum limit allowed by NEIL and has elected a 12-week waiting period.Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for the Company under the NEIL policies would be $41 million.Following the terrorist attacks of September 2001, both ANI and NEIL confirmed that terrorist acts against commercial nuclear power plants would, subject to the normal policy limits, be covered under their insurance.

Both companies, however, revised their policy terms on a prospective basis to include an industry aggregate for all"non-certified" terrorist acts, i.e., acts that are not certified acts of terrorism pursuant to the Terrorism Risk Insurance Act of 2002, which was renewed in 2005. The aggregate for all NEIL policies, which applies to non-certified 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.10. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial information for 2005 and 2004 are as follows: Net Income After Dividends on Preferred Stock Quarter Ended March 2005 June 2005 September 2005 December 2005 March 2004 June 2004 September 2004 December 2004 Operating Operating Revenues Income (in millions)-$ 970 1,086 1,458 1,134$ 960 1,059 1,246 971$157 253 443 161$202 239 415 164$ 93 122 236 57$ 91 104 220 66 The Company's business is influenced by seasonal weather conditions.

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 (in thousands)

$507,895 $481,171 $472,810 $461,355 $386,729 Cash Dividends on Common Stock (in thousands)

$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 (in thousands)

$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 President, Chairman and CEO, The Citizens Bank David J. Cooper, Sr.President, Cooper/T.

Smith Corporation R. Kent Henslee Managing Partner, Henslee, Robertson, Strawn &Knowles, L.L.C.John D. Johns Chairman, President and CEO, Protective Life Corporation Carl E. Jones, Jr.Chairman, Regions Financial Corporation Patricia M. King President and CEO, Sunny King Automotive Group James K. Lowder Chairman, The Colonial Company Wallace D. Malone, Jr.Vice Chairman, Wachovia Corporation Charles D. McCrary President and CEO, Alabama Power Company Dr. Malcolm Portera Chancellor, The University of Alabama System Robert D. Powers President, The Eufaula Agency David M. Ratcliffe Chairman, President and CEO Southern Company C. Dowd Ritter Chairman, President and CEO, AmSouth Bancorporation James H. Sanford Chairman, HOME Place Farms, Inc.John Cox Webb, IV President, Webb Lumber Company, Inc.James W. Wright Chairman, President and CEO, First Tuskegee Bank Charles D. McCrary President and Chief Executive Officer Art P. Beattie Executive Vice President, Chief Financial Officer and Treasurer C. Alan Martin Executive Vice President Steve R. Spencer Executive Vice President Rodney 0. Mundy Senior Vice President and Counsel Robert Holmes, Jr.Senior Vice President Robin A. Hurst Senior Vice President Michael L. Scott Senior Vice President Jerry L. Stewart Senior Vice President Philip C. Raymond Vice President and Comptroller William E. Zales, Jr.Vice President, Corporate Secretary and Assistant Treasurer Christopher T. Bell Vice President Robert A. Bell'Vice President Willard L. Bowers Yice President Larry R. Grill Vice President Donald R. Horsley 2 Vice President Gerald L. Johnson Vice President, Birmingham Division William B. Johnson Vice President Barbara J. Knight Vice President Ellen N. Lindemann 3 Vice President Gordon G. Martin Vice President, Southern Division Myrna J. Pittman Vice President Donald W. Reese Vice President R. Michael Saxon Vice President, Southeast Division Julia H. Segars Vice President Julian H. Smith, Jr.Vice President W. Ronald Smith Vice President, Eastern Division Zeke W. Smith Vice President Cheryl A. Thompson Vice President, Mobile Division Terry H. Waters Vice President, Western Division Robert Cole Giddens Assistant Comptroller E. Wayne Boston Assistant Secretary and Assistant Treasurer Ceila H. Shorts Assistant Secretary Kay 1. Worley Assistant Secretary J. Randy DeRieux Assistant Treasurer All information as of December 31, 2005 except as noted below' Elected 1/06 2 Elected 3/05 3 Resigned 2/06 53 CORPORATE INFORMATION Alabama Power Company 2005 Annual Report General This annual report is submitted for general information and is not intended for use in connection with any sale or purchase of, or any solicitation of offers to buy or sell securities.

Profile The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast.

The Company sells electricity to more than 1.4 million customers within its service area of approximately 45,000 square miles. In 2005, retail energy sales accounted for 72 percent of the Company's total sales of 77 billion kilowatt-hours.

The Company is a wholly owned subsidiary of The Southern Company, which is the parent company of five retail operating companies.

There is no established public trading market for the Company's common stock.Trustee, Registrar and Interest Paying Agent All series of First Mortgage Bonds, Senior Notes and Trust Preferred Securities JPMorgan Chase Bank, N.A.Institutional Trust Services 4 New York Plaza, 15k" Floor New York, NY 10004 The Flexible Money Market and 5.30% Series Class A Preferred Stock The Bank of New York 101 Barclay Street New York, NY 10286 Number of Preferred Shareholders of record as of December 31, 2005 was 1,701.Form 10-K A copy of the Form 10-K as filed with the Securities and Exchange Commission will be provided upon written request to the office of the Corporate Secretary.

For additional information, contact the office of the Corporate Secretary at (205) 257-3385.Alabama Power Company 600 North 18th Street Birmingham, AL 35203 (205) 257-1000 www.alabamapower.com Auditors Deloitte & Touche LLP 417 North 2 0'h Street Suite 1000 Birmingham, AL 35203 Legal Counsel Balch & Bingham LLP P.O. Box 306 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