Alabama Power Company
Annual Report 2008

Plain-text annual report

A L A B A M A P O W E R C O M P A N Y 2008 Annual Report MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Alabama Power Company 2008 Annual Report The management of Alabama Power Company (the “Company”) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a- 15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Under management’s supervision, an evaluation of the design and effectiveness of the Company’s internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2008. This Annual Report does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report. Charles D. McCrary President and Chief Executive Officer Art P. Beattie Executive Vice President, Chief Financial Officer, and Treasurer February 25, 2009 1 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, 2008 and 2007, 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, 2008. 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, such financial statements (pages 25 to 61) present fairly, in all material respects, the financial position of Alabama Power Company at December 31, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Birmingham, Alabama February 25, 2009 2 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Alabama Power Company 2008 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 constructive regulatory environment, to maintain energy sales in the midst of the current economic downturn, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long- term demand growth, increasingly stringent environmental standards, fuel prices, capital expenditures, and restoration following major storms. Appropriately balancing the need to recover these increasing costs with customer prices will continue to challenge the Company for the foreseeable future. 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 after dividends on preferred and preference stock. 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. The fossil/hydro 2008 Peak Season EFOR of 1.51% was better than the target. The nuclear generating fleet also uses Peak Season EFOR as an indicator of availability and efficient generation fleet operations during the peak season. The nuclear 2008 Peak Season EFOR of 2.78% did not meet the target. 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 performance for 2008 was better than the target for these reliability measures. Net income after dividends on preferred and preference stock is the primary component of the Company’s contribution to Southern Company’s earnings per share goal. The Company’s 2008 results compared with its targets for some of these key indicators are reflected in the following chart. Key Performance Indicator Customer Satisfaction Peak Season EFOR – fossil/hydro Peak Season EFOR – nuclear Net Income 2008 Target Performance Top quartile in customer surveys 2.75% or less 2.00% or less $617 million 2008 Actual Performance Top quartile 1.51% 2.78% $616 million See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The financial performance achieved in 2008 reflects the continued management emphasis, as well as the commitment shown by employees, in achieving or exceeding these key performance expectations. Earnings The Company’s financial performance remained strong in 2008 despite the challenges of a weakening economy and rising costs. The Company’s net income after dividends on preferred and preference stock of $616 million in 2008 increased $36 million (6.3%) over the prior year. This improvement was primarily due to an increase in retail base rate revenues resulting from an increase in rates under Rate Stabilization and Equalization Plan (Rate RSE) and Rate Certificated New Plant (Rate CNP) for environmental costs that took effect January 1, 2008, partially offset by higher non-fuel operating expenses and depreciation expense. 3 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report The Company’s 2007 net income after dividends on preferred and preference stock was $580 million, representing a $62 million (11.9%) increase from the prior year. This improvement was primarily due to an increase in retail base rate revenues resulting from an increase in rates under Rate RSE and Rate CNP for environmental costs that took effect January 1, 2007 as well as favorable weather conditions, partially offset by higher non-fuel operating expenses and increased interest expense. The Company’s 2006 net income after dividends on preferred and preference stock was $518 million, representing a $10 million (1.9%) increase from the prior year. This improvement was primarily due to retail and wholesale revenue growth offset by higher non-fuel operating expenses and increased interest expense. RESULTS OF OPERATIONS A condensed income statement follows: Operating revenues Fuel Purchased power Other operations and maintenance Depreciation and amortization Taxes other than income taxes Total operating expenses Operating income Total other income and (expense) Income taxes Net income Dividends on preferred and preference stock Net income after dividends on preferred and preference stock Amount 2008 $6,077 2,184 538 1,259 520 307 4,808 1,269 (246) 368 655 39 $ 616 Increase (Decrease) from Prior Year 2007 2006 2008 (in millions) $717 422 99 73 49 20 663 54 2 16 40 4 $ 36 $345 90 12 89 21 28 240 105 (11) 21 73 11 $ 62 $367 216 (31) 53 24 9 271 96 (40) 46 10 - $ 10 Operating Revenues Operating revenues for 2008 were $6.1 billion, reflecting a $717 million increase from 2007. The following table summarizes the principal factors that have affected operating revenues for the past three years: Retail – prior year Estimated change in – Rates and pricing Sales growth Weather Fuel and other cost recovery Retail – current year Wholesale revenues – Non-affiliates Affiliates Total wholesale revenues Other operating revenues Total operating revenues Percent change Amount 2008 2007 2006 $4,407.0 (in millions) $3,995.7 $3,621.4 246.1 26.8 (70.4) 252.8 4,862.3 711.9 308.5 1,020.4 194.2 $6,076.9 216.3 (4.9) 37.6 162.3 4,407.0 627.0 144.1 771.1 181.9 $5,360.0 48.4 35.8 19.9 270.2 3,995.7 634.6 216.0 850.6 168.4 $5,014.7 13.4% 6.9% 7.9% Retail revenues in 2008 were $4.9 billion. These revenues increased $455 million (10.3%) in 2008, $411 million (10.3%) in 2007, and $374 million (10.3%) in 2006. These increases were primarily due to increased fuel revenue and base rate increases of 5.6% in 4 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report January 2008, 5.3% in January 2007, and 2.6% in January 2006. 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. Wholesale revenues from sales to non-affiliated utilities were as follows: Unit power sales – Capacity Energy Total Other power sales – Capacity and other Energy Total Total non-affiliated 2008 2007 (in millions) 2006 $160 238 398 134 180 314 $712 $151 192 343 $154 198 352 128 156 284 $627 137 146 283 $635 Wholesale revenues from sales to non-affiliates will vary depending on the market cost of available energy compared to the cost of the Company and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and availability of Southern Company system generation. Wholesale revenues from sales to non-affiliates include unit power sales under long-term contracts to Florida utilities and sales to wholesale customers within the Company’s service territory. Capacity revenues under unit power sales contracts reflect the recovery of fixed costs and a return on investment, and under these contracts, energy is generally sold at variable cost. Fluctuations in oil and natural gas prices, which are the primary fuel sources for unit power sales customers, influence changes in these energy sales. However, because energy is generally sold at variable cost, these fluctuations have a minimal effect on earnings. No significant declines in the amount of capacity revenues are scheduled until the termination of the unit power sales contracts in May 2010. In June 2010, the units subject to the unit power sales contracts are expected to return to territorial service. As shown in the table above, unit power sales capacity revenues have ranged from $151 million to $160 million over the last three years. Short-term opportunity energy sales are also included in wholesale energy sales 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. Wholesale revenues from sales to affiliated companies within the Southern Company system 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 2008, wholesale revenues from sales to affiliates increased $164.4 million primarily due to a 62.2% increase in kilowatt-hour (KWH) sales to affiliates as a result of an increase in the availability of the Company’s generating resources because of a decrease in customer demand within the Company’s service territory. In 2007, wholesale revenues from sales to affiliates decreased $71.9 million primarily due to a 37.0% decrease in KWH sales to affiliates as a result of a decrease in the availability of the Company’s generating resources because of an increase in customer demand within the Company’s service territory. In 2006, wholesale revenues decreased $73.0 million primarily due to a 16.7% decrease in price and a 10.3% decrease in KWH sales to affiliates as a result of a decrease in the availability of the Company’s generating resources because of an increase in customer demand within the Company’s service territory. 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 (Rate ECR). Other operating revenues in 2008 increased $12.4 million (6.8%) from 2007 primarily due to an $11.7 million increase in revenues from gas-fueled co-generation steam facilities. In 2007, other operating revenues increased $13.5 million (8.0%) from 2006 primarily due to a $4.0 million increase in revenues from electric property associated with pole attachment and building rentals, a $2.6 million increase in transmission revenues, and a $2.5 million increase in revenues from gas-fueled co-generation steam facilities. In 2006, 5 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report other operating revenues decreased $17.6 million (9.5%) from 2005 primarily due to a decrease of $14.6 million in revenues from gas- fueled co-generation steam facilities mainly as a result of lower gas prices. Since co-generation steam revenues are generally offset by fuel expense, these revenues did not have a significant impact on earnings for any year reported. Energy Sales Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2008 and the percent change by year were as follows: Residential Commercial Industrial Other Total retail Wholesale - Non-affiliates Affiliates Total wholesale Total energy sales KWHs 2008 (in billions) 18.4 14.5 22.1 0.2 55.2 15.2 5.3 20.5 75.7 Percent Change 2007 2008 2006 (2.6)% (1.4) (3.2) 0.2 (2.5) (3.6) 62.2 7.6 0.0 1.3% 2.8 (1.6) 0.7 0.5 3.1% 2.1 (0.7) 0.4 1.2 (1.3) (37.0) (10.0) (2.4) 3.5 (10.3) (0.3) 0.8 Changes in retail energy sales are comprised of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales in 2008 were 2.5% less than in 2007. Energy sales were down in 2008 across all classes of customers. Residential and commercial sales decreased 2.6% and 1.4%, respectively, due primarily to milder weather in 2008 compared to 2007. Industrial sales decreased 3.2% during the year primarily as a result of decreased customer demand in the chemical and pipeline, and textiles and food sectors, as a result of a slowing economy that worsened during the fourth quarter of 2008. Retail energy sales in 2007 were 0.5% higher than in 2006. Energy sales in the residential and commercial sectors led the growth with a 1.3% and a 2.8% increase, respectively, due primarily to weather-driven increased demand. Industrial sales decreased 1.6% during the year primarily as a result of decreased sales demand in textiles and food, primary metals, and chemical sectors. Retail energy sales in 2006 were 1.2% higher than in 2005. Energy sales in the residential and commercial sectors led the growth with a 3.1% and a 2.1% increase, respectively, due primarily to weather-driven increased demand. Industrial sales decreased 0.7% as several large textile facilities discontinued or substantially reduced their operations in 2006. In addition, industrial sales decreased due to pulp and paper customers utilizing self-generation as a result of lower gas prices during the year compared to 2005. 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 generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market. Details of the Company’s electricity generated and purchased were as follows: Total generation (billions of KWHs) Total purchased power (billions of KWHs) Sources of generation (percent) – Coal Nuclear Gas Hydro Cost of fuel, generated (cents per net KWH) – Coal Nuclear Gas Average cost of fuel, generated (cents per net KWH) Average cost of purchased power (cents per net KWH) 2008 70.0 9.2 66 20 11 3 2.94 0.50 8.30 3.00 7.44 2007 69.8 9.6 69 19 10 2 2.14 0.50 7.43 2.36 6.07 2006 72.0 8.9 68 19 9 4 2.09 0.47 7.87 2.27 5.98 6 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report Fuel and purchased power expenses were $2.7 billion in 2008, an increase of $521.5 million (23.7%) above the prior year costs. This increase was the result of a $560.8 million increase in the cost of fuel, offset by a $39.3 million decrease related to the volume of KWHs generated and purchased. Fuel and purchased power expenses were $2.2 billion in 2007, an increase of $101.9 million (4.9%) above the prior year costs. This increase was the result of a $70.3 million increase in the cost of fuel and a $31.6 million increase related to the volume of KWHs generated and purchased. Fuel and purchased power expenses were $2.1 billion in 2006, an increase of $184.1 million (9.6%) above the prior year costs. This increase was the result of a $128.7 million increase in the cost of fuel and a $55.4 million increase related to the volume of KWHs generated and purchased. Purchased power consists of purchases from affiliates in the Southern Company system and non-affiliated companies. Purchased power transactions among the Company, its affiliates, and non-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 $81.9 million (84.5%) in 2008 due to a 67.9% increase in the amount of energy purchased. In 2007, purchased power from non- affiliates decreased $27.1 million (21.8%) due to a 22.6% decrease in the amount of energy purchased over the previous year. In 2006, purchased power from non-affiliates decreased $64.7 million (34.3%) due to a 26.8% decrease in the amount of energy purchased and a 10.3% decrease in purchased power prices over the previous year. Over the last several years, coal prices have been influenced by a worldwide increase in demand from developing countries, as well as increases in mining and fuel transportation costs. In the first half of 2008, coal prices reached unprecedented high levels primarily due to increased demand following more moderate pricing in 2006 and 2007. Despite these fluctuations, fuel inventories have been adequate and fuel supply markets have been sufficient to meet expected fuel requirements. Demand for natural gas in the United States also increased in 2007 and the first half of 2008. However, natural gas supplies increased in the last half of 2008 as a result of increased production and higher storage levels due in part to weak industrial demand. Both coal and natural gas prices moderated in the second half of 2008 as the result of a recessionary economy. During 2008, uranium prices continued to moderate from the highs set during 2007. While worldwide uranium production levels appear to have increased slightly since 2007, secondary supplies and inventories were still required to meet worldwide reactor demand. Fuel and purchased power expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s Rate ECR. The Company, along with the Alabama Public Service Commission (PSC), continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. 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 Operations and Maintenance Expenses In 2008, other operations and maintenance expenses increased $72.7 million (6.1%) primarily due to a $27.4 million increase in steam production expense related to environmental mandates (which were offset by revenues associated with Rate CNP environmental) and scheduled outage costs, a $22.9 million increase in nuclear production expense related to operations and scheduled outage costs, and a $19.9 million increase in transmission and distribution expense related to overhead line clearing costs. In 2007, other operations and maintenance expenses increased $89.3 million (8.1%) primarily due to a $28.5 million increase in steam production expense related to environmental mandates and scheduled outage costs, a $19.6 million increase in transmission and distribution expense related to overhead line clearing costs, a $19.0 million increase in administrative and general expenses related to an increase in the expenses for the injuries and damages reserve, outside services, and employee benefits, an $8.1 million increase in nuclear production expense related to scheduled outage cost, and a $4.7 million increase in customer accounts expense associated with customer service expenses. In 2006, other operations and maintenance expenses increased $52.8 million (5.1%) primarily due to an $18.8 million increase in administrative and general expenses related to employee benefits, a $10.1 million increase in nuclear production expense related to both routine operation and scheduled outage costs, a $9.8 million increase in transmission and distribution expense related to overhead and underground line costs, and a $5.4 million increase in steam production expense related to environmental costs. 7 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report Depreciation and Amortization Depreciation and amortization expenses increased $48.9 million (10.4%) in 2008, $20.5 million (4.5%) in 2007, and $24.5 million (5.7%) in 2006, primarily due to additions to property, plant, and equipment related to environmental mandates (which were offset by revenues associated with Rate CNP environmental) and distribution projects. During 2008, a depreciation study was completed based on information as of December 31, 2007. The study was filed with the FERC on October 29, 2008 and was also provided to the Alabama PSC. The proposed rates result in an expected increase in depreciation expense for 2009 of approximately $29 million. Taxes Other Than Income Taxes Taxes other than income taxes increased $19.9 million (7.0%) in 2008, $28.4 million (11.0%) in 2007, and $9.3 million (3.7%) in 2006, primarily due to increases in state and municipal public utility license taxes which are directly related to the increase in retail revenues. Allowance for Equity Funds Used During Construction Allowance for equity funds used during construction (AFUDC) increased $10.1 million (28.5%) in 2008 and $17.2 million (94.1%) in 2007, primarily due to increases in the amount of construction work in progress related to environmental mandates at generating facilities and transmission and distribution projects compared to the prior years. In 2006, AFUDC decreased $2.0 million (10.0%) primarily due to the timing of construction expenditures compared to the prior year. See Note 1 to the financial statements under “Allowance for Funds Used During Construction (AFUDC)” for additional information. Income Taxes Income taxes increased $16.6 million (4.7%) in 2008, primarily due to higher pre-tax income partially offset by the tax benefit associated with an increase in AFUDC and a decrease in expense related to tax contingencies. Income taxes increased $20.9 million (6.3%) in 2007, primarily due to higher pre-tax income partially offset by the tax benefit associated with an increase in AFUDC and an increase in the Internal Revenue Code of 1986, as amended (Internal Revenue Code), Section 199 production activities deduction. Income taxes increased $45.6 million (16.0%) in 2006, primarily due to higher pre-tax income and the impact of a 2005 accounting order approved by the Alabama PSC to return certain regulatory liabilities related to deferred taxes to Alabama Power’s retail customers. See Note 5 to the financial statements for additional information. Effects of Inflation The Company is subject to rate regulation that is based on the recovery of costs. Retail rates may be adjusted annually based on historical or projected costs, including estimates for inflation. When historical costs are included, or when inflation exceeds the projected costs used in rate regulation or market-based prices, the effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. In addition, the income tax laws are based on historical costs. Any adverse effect of inflation on the Company’s results of operations has not been substantial. See Note 3 to financial statements under “Retail Regulatory Matters – Rate RSE” for additional information. FUTURE EARNINGS POTENTIAL General The Company operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service area located in the State of Alabama in addition 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 wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated 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 regulatory matters. 8 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report 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 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 constructive regulatory environment that continues to allow for the recovery of all prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales during the current economic downturn, 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 or decline in the Company’s service area. Recent recessionary conditions have negatively impacted sales growth. The timing and extent of the economic recovery will impact future earnings. Environmental Matters Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. Some of the factors driving the potential for such an increase are higher commodity costs, market demand for labor, and scope additions and clarifications. The timing, specific requirements, and estimated costs could also change as environmental statutes and regulations are adopted or modified. See Note 3 to the financial statements under “Environmental Matters” for additional information. 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 certain Southern Company subsidiaries, including the Company, alleging that it had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against the Company in the U.S. District Court for the Northern District of Alabama after the Company was dismissed from the original action. In this lawsuit, the EPA alleged that NSR violations occurred at five coal-fired generating facilities operated by the Company. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between the Company and the EPA, resolving a portion of the Company’s lawsuit relating to the alleged NSR violations at Plant Miller. The consent decree required the Company to pay $100,000 to resolve the government’s claim for a civil penalty and to donate $4.9 million of sulfur dioxide emission allowances to a nonprofit charitable organization. It also formalized specific emissions reductions to be accomplished by the Company, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in Alabama granted the Company’s motion for summary judgment and entered final judgment in favor of the Company on the EPA’s claims related to all of the remaining plants: Plants Barry, Gaston, Gorgas, and Greene County. The plaintiffs appealed the district court’s decision to the U.S. Court of Appeals for the Eleventh Circuit, where the appeal was stayed, pending the U.S. Supreme Court’s decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke Energy case in April 2007, and in December 2007, the Eleventh Circuit vacated the district court’s decision in the Company’s case and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court’s decision in the Duke Energy case. On July 24, 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of the Company regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. The decision did not resolve the case and the ultimate outcome of this matter cannot be determined at this time. 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 $37,500 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 or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. 9 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report Carbon Dioxide Litigation New York Case In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. 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. The plaintiffs have not, however, requested that damages be awarded in 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 in October 2005, but no decision has been issued. The ultimate outcome of these matters cannot be determined at this time. Kivalina Case On February 26, 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. On June 30, 2008, all defendants filed motions to dismiss this case. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. The ultimate outcome of this matter 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; the Endangered Species Act; and related federal and state regulations. 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 2008, the Company had invested approximately $2.3 billion in capital projects to comply with these requirements, with annual totals of $617 million, $469 million, and $260 million for 2008, 2007, and 2006, respectively. The Company expects that capital expenditures to assure compliance with existing and new statutes and regulations will be an additional $584 million, $131 million, and $59 million for 2009, 2010, and 2011, respectively. The Company’s compliance strategy can be affected by changes to existing environmental laws, statutes, and regulations, the cost, availability, and existing inventory of emission allowances, and the Company’s fuel mix. 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 any new federal or state legislation or regulations related to global climate change, air quality, combustion byproducts, including coal ash, or other environmental and health concerns could also significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the Company’s operations, 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 2008, the Company had spent approximately $2.0 billion in reducing sulfur dioxide (SO2) and nitrogen oxide (NOx) 10 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls are currently being installed at several plants to further reduce air emissions, maintain compliance with existing regulations, and meet new requirements. In 2004, the EPA designated nonattainment areas under an eight-hour ozone standard. The Birmingham area was originally designated as nonattainment under the eight-hour ozone standard, but has since been redesignated as an attainment area by the EPA, and a maintenance plan to address future exceedances of the standard has been approved. On March 12, 2008, the EPA issued a final rule establishing a more stringent eight-hour ozone standard which will likely result in designation of new nonattainment areas within the Company’s service territory. The EPA is expected to publish those designations in 2010, and require state implementation plans for any nonattainment areas by 2013. During 2005, the EPA’s annual fine particulate matter nonattainment designations became effective for several areas within the Company’s service territory, including the Birmingham area. State plans for addressing the nonattainment designations for this standard were due by April 5, 2008 but have not been finalized. These state plans could require further reductions in SO2 and NOx emissions from power plants. In September 2006, the EPA published a final rule which increased the stringency of the 24-hour average fine particulate matter air quality standard. On December 18, 2008, the EPA designated the Birmingham area as nonattainment for the 24-hour standard. A state implementation plan for this nonattainment area is due in 2012. The EPA issued the final Clean Air Interstate Rule (CAIR) in March 2005. This cap-and-trade rule addresses power plant SO2 and NOx emissions 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 NOx and/or SO2 to be achieved in two phases, 2009/2010 and 2015. On July 11, 2008, in response to petitions brought by certain states and regulated industries challenging particular aspects of CAIR, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating CAIR in its entirety and remanding it to the EPA for further action consistent with its opinion. On December 23, 2008, however, the U.S. Court of Appeals for the District of Columbia Circuit altered its July decision in response to a rehearing petition and remanded CAIR to the EPA without vacatur, thereby leaving CAIR compliance requirements in place while the EPA develops a revised rule. The State of Alabama has completed its plan to implement CAIR. Emission reductions are being accomplished by the installation of emission controls at the Company’s coal-fired facilities and/or by the purchase of emission allowances. The full impact of the court's remand and the outcome of the EPA's future rulemaking in response cannot be determined at this time. The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized in July 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 (1) the application of Best Available Retrofit Technology (BART) to certain sources built between 1962 and 1977 and (2) the application of any additional emissions reductions which may be deemed necessary for each designated area to achieve reasonable progress by 2018 toward the natural conditions goal. Thereafter, for each 10-year planning period, additional emissions reductions will be required to continue to demonstrate reasonable progress in each area during that period. For power plants, the Clean Air Visibility Rule allows states to determine that the CAIR satisfies BART requirements for SO2 and NOx. Extensive studies were performed for each of the Company’s affected units to demonstrate that additional particulate matter controls are not necessary under BART. The state of Alabama has determined that no additional SO2 controls beyond CAIR are needed to satisfy reasonable progress. States have completed or are currently completing implementation plans that contain strategies for BART and any other measures required to achieve the first phase of reasonable progress. The impacts of the eight-hour ozone nonattainment designations, the fine particulate matter nonattainment designations, and the Clean Air Visibility Rule on the Company cannot be determined at this time and will depend on the resolution of any pending legal challenges and the development and implementation of rules at the state level. The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO2 and NOx emission controls within the next several years to ensure continued compliance with applicable air quality requirements. In March 2005, the EPA published the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The final Clean Air Mercury Rule was challenged in the U.S. Court of Appeals for the District of Columbia Circuit. The petitioners alleged that the EPA was not authorized to establish a cap-and-trade program for mercury emissions and instead the EPA must establish maximum achievable control technology standards for coal-fired electric utility steam generating units. On February 8, 2008, the court ruled in favor of the petitioners and vacated the Clean Air Mercury Rule. The 11 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report Company’s overall environmental compliance strategy relies primarily on a combination of SO2 and NOx controls to reduce mercury emissions. Any significant changes in the strategy will depend on the outcome of any appeals and/or future federal and state rulemakings. Future rulemakings necessitated by the court’s decision could require emission reductions more stringent than those required by the Clean Air Mercury Rule. Water Quality In July 2004, the EPA published its final technology-based regulations under the Clean Water Act for the purpose of reducing impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures. The rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants. In January 2007, the U.S. Court of Appeals for the Second Circuit overturned and remanded several provisions of the rule, including the use of cost-benefit analysis, to the EPA for revisions. The decision has been appealed to the U.S. Supreme Court. The full impact of these regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, 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 be determined at this time. Environmental Remediation The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases 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. See Note 3 to the financial statements under “Environmental Matters – Environmental Remediation” for additional information. Global Climate Issues Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions and renewable energy standards continue to be strongly considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. The ultimate outcome of these proposals cannot be determined at this time; however, mandatory restrictions on the Company’s greenhouse gas emissions could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. The EPA is currently developing its response to this decision. Regulatory decisions that will follow from this response may have implications for both new and existing stationary sources, such as power plants. The ultimate outcome of these rulemaking activities cannot be determined at this time; however, as with the current legislative proposals, mandatory restrictions on the Company’s greenhouse gas emissions could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. In addition, some states are considering or have undertaken actions to regulate and reduce greenhouse gas emissions. For example, on June 25, 2008, Florida’s Governor signed comprehensive energy-related legislation that includes authorization for the Florida Department of Environmental Protection to adopt rules for a cap-and-trade regulatory program to address greenhouse gas emissions from electric utilities, conditioned upon their ratification by the legislature no sooner than the 2010 legislative session. This legislation also authorizes the Florida PSC to adopt a renewable portfolio standard for public utilities, subject to legislative ratification. The impact of any similar state legislation on the Company will depend on the future development, adoption, legislative ratification, implementation, and potential legal challenges to rules governing greenhouse gas emissions and mandates regarding the use of renewable energy, and the ultimate outcome cannot be determined at this time. International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. Current efforts focus on a potential successor to the Kyoto Protocol for the post 2012 timeframe, with a conclusion to this round of negotiations targeted for the end of 2009. The outcome and impact of the international negotiations cannot be determined at this time. 12 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report The Company continues to evaluate its future energy and emission profiles and is participating in voluntary programs to reduce greenhouse gas emissions and to help develop and advance technology to reduce emissions. FERC Matters Market-Based Rate Authority The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. 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 the proceeding. Any new market-based rate sales by the Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level. In November 2007, the presiding administrative law judge issued an initial decision regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the Company 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, and could also result in total refunds of up to $3.9 million, plus interest. The Company believes that there is no meritorious basis for an adverse decision in this proceeding and is vigorously defending itself in this matter. In June 2007, the FERC issued its final rule in Order No. 697 regarding market-based rate authority. The FERC generally retained its current market-based rate standards. Responding to a number of requests for rehearing, the FERC issued Order No. 697-A on April 21, 2008 and Order No. 697-B on December 12, 2008. These orders largely affirmed the FERC’s prior revision and codification of the regulations governing market-based rates for public utilities. In accordance with the orders, Southern Company submitted to the FERC an updated market power analysis on September 2, 2008 related to its continued market-based rate authority. The ultimate outcome of this matter cannot now be determined. On October 17, 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On December 18, 2008, the FERC issued an order conditionally accepting the MBR tariff subject to certain revisions to the auction proposal. On January 21, 2009, Southern Company made a compliance filing that accepted all the conditions of the MBR tariff order. When this order becomes final, Southern Company will have 30 days to implement the wholesale auction. On December 31, 2008, the FERC issued an order conditionally accepting the CBR tariff subject to providing additional information concerning one aspect of the tariff. On January 30, 2009, Southern Company filed a response addressing the FERC inquiry to the CBR tariff order. Implementation of the energy auction in accordance with the MBR tariff order is expected to adequately mitigate going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory. The timing of when the FERC may issue the final orders on the MBR and CBR tariffs and the ultimate outcome of these matters cannot be determined at this time. Generation Interconnection Agreements In November 2004, generator company subsidiaries of Tenaska, Inc. (Tenaska), as counterparties to two previously executed interconnection agreements with the Company, filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $11.0 million previously paid for interconnection facilities. No other similar complaints are pending with the FERC. In January 2007, the FERC issued an order granting Tenaska’s requested relief. Although the FERC’s order required the modification of Tenaska’s interconnection agreements, under the provisions of the order, the Company determined that no refund was payable to Tenaska. The Company requested rehearing asserting that the FERC retroactively applied a new principle to existing interconnection agreements. Tenaska requested rehearing of FERC’s methodology for determining the amount of refunds. The requested rehearings 13 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report were denied and the Company and Tenaska have appealed the orders to the U.S. Circuit Court for the District of Columbia. The final outcome of this matter cannot now be determined. 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 expired in July and August of 2007. Since the FERC did not act on the Company’s new license applications prior to the expiration of the existing licenses, the FERC is required by law to issue annual licenses to the Company, under the terms and conditions of the existing license, until action is taken on the new license applications. The FERC issued an annual license for the Coosa developments in August 2007 and issued an annual license for the Warrior developments in September 2007. These annual licenses are automatically renewed each year without further action by the FERC to allow the Company to continue operation of the projects under the terms of the previous license while the FERC completes review of the applications for new licenses. In 2006, the Company initiated the process of developing an application to relicense the Martin hydroelectric project located on the Tallapoosa River. The current Martin license will expire in 2013 and the application for a new license is expected to be filed with the FERC in 2011. Upon or after the expiration of each license, the U.S. 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 timing and final outcome of the Company’s relicense applications cannot now be determined. PSC Matters Retail Rate Adjustments In October 2005, the Alabama PSC approved a revision to Rate RSE requested by the Company. Effective January 2007 and thereafter, Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4% per year and any annual adjustment is limited to 5%. Retail rates remain unchanged when the return on retail common equity is projected to be between 13.0% and 14.5%. 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. On October 7, 2008, the Alabama PSC approved a corrective rate package primarily providing for adjustments associated with customer charges to certain existing rate structures. This package, effective in January 2009, is expected to generate additional annual revenues of approximately $168 million. The Company agreed to a moratorium on any increase in rates in 2009 under Rate RSE. On December 1, 2008, the Company made its submission of projected data for calendar year 2009. 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 power purchase agreements (PPAs) under Rate CNP. In April 2006, an annual adjustment to Rate CNP, associated with PPAs, increased retail rates by approximately 0.5%, or $19 million annually. There was no rate adjustment associated with the annual adjustment to Rate CNP, associated with PPAs, or the true-up adjustment in April 2007 and 2008. There will be no adjustment to the current Rate CNP to recover certificated PPA costs in April 2009. See Note 3 to the financial statements under “Retail Regulatory Matters – Rate CNP” for additional information. Rate CNP also allows for the recovery of the Company’s retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism, based on forward-looking information provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on invested capital. Retail rates increased due to environmental costs approximately 1.2% in January 2006, 0.6% in January 2007, and 2.4% in January 2008. On October 7, 2008, the Alabama PSC approved a corrective rate package primarily providing for adjustments associated with customer charges to certain existing rate structures. As a part of the Alabama PSC approval of the corrective rate package, the Alabama PSC and the Company agreed to defer any environmental rate increase from 2009 to 2010. This 14 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report deferral will have an immaterial impact on annual cash flows, and will have no significant effect on the Company’s revenues or net income. On December 1, 2008, the Company made its submission of projected data for calendar year 2009. See Note 3 to the financial statements under “Retail Regulatory Matters” for further information. Retail Fuel Cost Recovery The Company has established fuel cost recovery rates approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. The Company, along with the Alabama PSC, will continue to monitor the under recovered fuel cost balance to determine whether an additional adjustment to billing rates is required. In June 2007, the Alabama PSC ordered the Company to increase its Rate ECR factor to 3.100 cents per KWH effective with billings beginning July 2007 for the 30-month period ending December 2009. The previous rate of 2.400 cents per KWH had been in effect since January 2006. This increase was intended to permit recovery of energy costs based on an estimate of future energy cost, as well as the collection of the existing under recovered energy cost by the end of 2009. During the recovery period, the Company was allowed to include a carrying charge associated with the under recovered fuel costs in the fuel expense calculation. In the event the application of this increased Rate ECR factor results in an over recovered position during this period, the Company would pay interest on any such over recovered balance at the same rate used to derive the carrying cost. On October 7, 2008, the Alabama PSC approved an increase in the Company’s Rate ECR factor to 3.983 cents per KWH for a 24- month period beginning with October 9, 2008 billings. Thereafter, the Rate ECR factor is 5.910 cents per KWH, absent a contrary order by the Alabama PSC. The previous rate of 3.100 cents per KWH had been in effect since June 2007. During the 24-month period, the Company will be allowed to continue to include a carrying charge associated with the under recovered fuel costs in the fuel expense calculation. In the event the application of this increased Rate ECR factor results in an over recovered position during this period, the Company will pay interest on any such over recovered balance at the same rate used to derive the carrying cost. The Company’s under recovered fuel costs as of December 31, 2008 totaled $305.8 million as compared to $279.8 million at December 31, 2007. As a result of the Alabama PSC orders, the Company classified $180.9 million and $81.7 million of the under recovered regulatory clause revenues as deferred charges and other assets in the balance sheets as of December 31, 2008 and December 31, 2007, respectively. This classification is based on an estimate which includes such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of the recovery of the under recovered fuel costs. 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 Based on an order from the Alabama PSC, the Company maintains a reserve for operations and maintenance expense to cover the cost of damages from major storms to its transmission and distribution facilities. See Note 1 and Note 3 to the financial statements under “Natural Disaster Reserve” and “Retail Regulatory Matters - Natural Disaster Cost Recovery,” respectively, for additional information on these reserves. In December 2005, the Alabama PSC approved a request by the Company to replenish the depleted natural disaster reserve (NDR) due to hurricanes in 2005 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 in 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. Assuming no additional storms, the Company currently expects that the target reserve balance could be achieved within three years. The second component of the NDR charge is intended to allow recovery of any existing deferred hurricane related operations and maintenance costs and any future reserve deficits over a 24-month period. Absent further Alabama PSC approval, 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. 15 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report At December 31, 2008, the Company had an accumulated balance of $33.2 million in the target reserve for future storms, which is included in the balance sheets under “Other Regulatory Liabilities.” In June 2007, the Company fully recovered its storm costs of $51.3 million resulting from previous hurricanes. As a result, customer rates decreased by this portion of the NDR charge effective in July 2007. As revenue from the NDR charge is recognized, an equal amount of operations and maintenance expenses 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 annual cash flow. Income Tax Matters Legislation On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives. These incentives could have a significant impact on the Company’s future cash flow and net income. Additionally, the ARRA includes programs for renewable energy, transmission and smart grid enhancement, fossil energy and research, and energy efficiency and conservation. The ultimate impact cannot be determined at this time. Internal Revenue Code Section 199 Domestic Production Deduction The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 (production activities deduction) of the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for years 2007 through 2009, and a 9% rate thereafter. The Internal Revenue Service has not clearly defined a methodology for calculating this deduction. However, Southern Company has agreed with the IRS on a calculation methodology and signed a closing agreement on December 11, 2008. Therefore, the Company reversed the unrecognized tax benefit and adjusted the deduction to conform to the agreement. The net impact of the reversal of the unrecognized tax benefits combined with the application of the new methodology had no material effect on the Company’s financial statements. See Note 5 to the financial statements under “Effective Tax Rate” for additional information. 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 $26 million, $17 million, and $13 million in 2008, 2007, and 2006, respectively. Postretirement benefit costs for the Company were $23 million, $27 million, and $28 million in 2008, 2007, and 2006, respectively. 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. In addition, 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, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water 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 current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements. See Note 3 to the financial statements for information regarding material issues. 16 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 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 1 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. Senior management has reviewed and discussed critical accounting policies and estimates described below 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” (SFAS 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 SFAS 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 financial statements than they would on a non-regulated company. As reflected in Note 1 to the financial statements under “Regulatory Assets and Liabilities,” significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of 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 results of operations. 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, in accordance with generally accepted accounting principles, records reserves for those matters where a non-tax- related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. 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 IRS or Alabama Department of Revenue interpretations of existing regulations. Identification of 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 new or existing matters through the legislative process, the court systems, the IRS, the FERC, or the EPA. 17 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report Unbilled Revenues Revenues related to the retail 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. FINANCIAL CONDITION AND LIQUIDITY Overview The Company’s financial condition remained stable at December 31, 2008. Throughout the recent turmoil in the financial markets, the Company has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper programs and variable rate pollution control revenue bonds. The Company has continued to issue commercial paper at reasonable rates. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. No material changes in bank credit arrangements have occurred, although market rates for committed credit have increased and the Company may be subject to higher costs as its existing facilities are replaced or renewed. The Company’s interest cost for short-term debt has decreased as market short- term interest rates have declined. The ultimate impact on future financing costs as a result of the financial turmoil cannot be determined at this time. The Company experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information. The Company’s investments in pension and nuclear decommissioning trust funds declined in value as of December 31, 2008. The Company expects that the earliest that cash may have to be contributed to the pension trust fund is 2011 and such contribution could be significant; however, projections of the amount vary significantly depending on interpretations of and decisions related to federal legislation passed during 2008 as well as other key variables including future trust fund performance and cannot be determined at this time. The Company does not expect any changes to the funding obligations to the nuclear decommissioning trust at this time. Net cash provided from operating activities in 2008 totaled $1.2 billion, an increase of $30 million as compared to 2007. Significant changes in operating cash flow for 2008 included an increase in the use of funds for fossil fuel inventory and payment of operating expenses along with a higher receivables balance as compared 2007. This use of funds was offset by an increase in cash from net income as previously discussed and higher depreciation expense along with a decrease in the payments for federal taxes as compared to 2007. Net cash provided from operating activities in 2007 totaled $1.2 billion, an increase of $194 million as compared to 2006. The increase was primarily due to an increase in net income resulting from price increases, an increase in deferred taxes and the timing of payments related to operating expenses. Net cash provided from operating activities in 2006 totaled $956 million, an increase of $48 million as compared to 2005. The increase was primarily due to higher recovery rates for fuel and purchased power partially offset by the timing of payments for operating expenses. Net cash used for investing activities totaled $1.6 billion, $1.3 billion, and $1.0 billion for 2008, 2007, and 2006, respectively, primarily due to gross property additions to utility plant of $1.5 billion, $1.2 billion and $0.9 billion for 2008, 2007, and 2006, respectively. These additions were primarily related to construction of transmission and distribution facilities, replacement of steam generation equipment, purchases of nuclear fuel, and environmental mandates. Net cash provided from financing activities totaled $375 million in 2008, $162 million in 2007, and $14 million in 2006 primarily due to long term debt issuances and cash raised from common stock sales in excess of redemptions of securities and dividends paid. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and securities redeemed. Significant balance sheet changes for 2008 include an increase of $966 million in gross plant and an increase of $855 million in long- term debt, primarily due to an increase in environmental-related equipment. Other significant balance sheet changes were a result of a decline in the market value of the Company’s pension trust and nuclear decommissioning trust funds, impacting the Company’s other regulatory assets and liabilities. See Note 1 to the financial statements under “Regulatory Assets and Liabilities” and “Nuclear 18 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report Decommissioning” and Note 2 under “Pension Plans” for additional information. In 2007, significant balance sheet changes included an increase of $671 million in gross plant and an increase of $602 million in long-term debt, primarily due to an increase in environmental-related equipment. The Company’s ratio of common equity to total capitalization, including short-term debt, was 42.5% in 2008, 42.5% in 2007, and 42.1% in 2006. See Note 6 to the financial statements for additional information. The Company has maintained investment grade credit ratings from the major rating agencies with respect to debt, preferred securities, preferred stock, and preference stock. See SELECTED FINANCIAL AND OPERATING DATA for additional information regarding the Company’s securities ratings. 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, unsecured debt, common stock, preferred stock, and preference stock. However, the type and timing of any financings will depend on market conditions, regulatory approval, and other factors. Security issuances are subject to regulatory approval by the Alabama PSC. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission under the Securities Act of 1933, as amended. The amounts of securities authorized by the Alabama PSC 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 sometimes exceed current assets because of the Company’s debt due within one year and the periodic use of short-term debt as a funding source primarily 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 December 31, 2008, the Company had approximately $28.2 million of cash and cash equivalents and $1.3 billion 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 a commercial paper program, to meet liquidity needs. The Company maintains committed lines of credit in the amount of $1.3 billion, of which $466 million will expire at various times during 2009. $379 million of the credit facilities expiring in 2009 allow for the execution of term loans for an additional one-year period. $765 million of credit facilities expire in 2012. 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 at the request and for the benefit of the Company and the other traditional 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 traditional operating company. The obligations of each company under these arrangements are several and there is no cross affiliate credit support. As of December 31, 2008, the Company had $25 million of commercial paper outstanding. As of December 31, 2007, the Company had no commercial paper outstanding. 19 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report Financing Activities During 2008, the Company issued $850 million of senior notes and incurred obligations related to the issuance of $254 million of tax- exempt bonds. In addition, the Company issued a total of 7.5 million shares of its common stock at $40.00 per share and realized proceeds of $300 million. The proceeds of these issuances were used to repay short-term indebtedness, to fund certain pollution control, environmental improvement facilities and solid waste disposal facilities, and for general corporate purposes. Also during 2008, the Company paid at maturity $410 million of senior notes and redeemed 1,250 shares of its Flexible Money Market Class A Preferred Stock (Series 2003A), Stated Capital $100,000 Per Share ($125 million aggregate value). Also during 2008, the Company entered into $330 million notional amount of interest rate swaps related to variable rate pollution control revenue bonds to hedge changes in interest rates for the period February 2008 through February 2010. The weighted average fixed payment rate on these hedges is 2.49% and the Company now has a total of $576 million of such hedges in place, with an overall weighted average fixed payment rate of 2.69%. The Company converted its $246.5 million obligation related to auction rate pollution control revenue bonds from an auction rate mode to fixed rate interest modes. With the completion of this conversion in March 2008, none of the outstanding securities or obligations of the Company is subject to an auction rate mode. Also during 2008, the Company was required to purchase a total of approximately $11 million of variable rate pollution control revenue bonds that were tendered by investors, all of which were subsequently remarketed. In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. 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. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are primarily for fuel purchases, fuel transportation and storage, emission allowances, and energy price risk management. At December 31, 2008, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $2 million. At December 31, 2008, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $99 million. Included in these amounts are certain agreements that could require collateral in the event that one or more power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact the Company’s ability to access capital markets, particularly the short-term debt market. 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, where possible, 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. 20 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report To mitigate future exposure to changes in interest rates, the Company enters into forward starting interest rate swaps and other derivatives that have been designated as hedges. The weighted average interest rate on $250 million of long-term variable interest rate exposure that has not been hedged at January 1, 2009 was 2.34%. 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 $2.5 million at January 1, 2009. 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 financial hedge contracts for natural gas purchases. The Company has implemented fuel hedging programs per the guidelines 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% 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% of the Company’s natural gas budget for that year. The changes in fair value of energy-related derivative contracts were as follows at December 31: 2008 Changes 2007 Changes Fair Value (in millions) Contracts outstanding at the beginning of the period, assets (liabilities), net Contracts realized or settled Current period changes(a) Contracts outstanding at the end of the period, assets (liabilities), net $ (0.4) (44.0) (47.5) $(91.9) $(32.6) 31.5 0.7 $ (0.4) (a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any. The decrease in the fair value positions of the energy-related derivative contracts for the year-ended December 31, 2008 was $91.5 million, substantially all of which is due to natural gas positions. This change is attributable to both the volume and prices of natural gas. At December 31, 2008, the Company had a net hedge volume of 44.5 billion cubic feet (Bcf) with a weighted average contract cost approximately $2.12 per million British thermal units (mmBtu) above market prices, and 27.4 Bcf at December 31, 2007 with a weighted average contract cost approximately $0.02 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the fuel cost recovery clauses. At December 31, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as assets/(liabilities) as follows: Regulatory hedges Cash flow hedges Non-accounting hedges Total fair value 2008 (in millions) $(91.9) - - $(91.9) 2007 $(0.7) 0.5 (0.2) $(0.4) Energy-related derivative contracts which are designated as regulatory hedges relate to the Company’s fuel hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clauses. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in other comprehensive income before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. Unrealized pre-tax gains and losses from energy-related derivative contracts recognized in income were not material for any year presented. 21 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at December 31, 2008 are as follows: December 31, 2008 Fair Value Measurements Total Fair Value Maturity Year 1 Years 2&3 Years 4&5 Level 1 Level 2 Level 3 Fair value of contracts outstanding at end of period $ - (91.9) - $ (in millions) - $ (71.4) - - (20.5) - $(91.9) $(71.4) $(20.5) $ - - - $ - As part of the adoption of FASB Statement No. 157, “Fair Value Measurements” to increase consistency and comparability in fair value measurements and related disclosures, the table above now uses the three-tier fair value hierarchy, as discussed in Note 10 to the financial statements, as opposed to the previously used descriptions “actively quoted,” “external sources,” and “models and other methods.” The three-tier fair value hierarchy focuses on the fair value of the contract itself, whereas the previous descriptions focused on the source of the inputs. Because the Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, the valuations of those contracts now appear in Level 2; previously they were shown as “actively quoted.” The Company is exposed to market risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. The Company’s practice 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 $1.4 billion for 2009, $1.0 billion for 2010, and $1.0 billion for 2011. Environmental expenditures included in these estimated amounts are $584 million, $131 million, and $59 million for 2009, 2010, and 2011, respectively. Also included over the next three years, the Company estimates spending $586 million on Plant Farley (including $341 million for nuclear fuel), $950 million on distribution facilities, and $387 million on transmission additions. See Note 7 to the financial statements under “Construction Program” for additional details. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; revised load growth estimates; changes in environmental statutes and regulations; changes in nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; Alabama PSC approvals; 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. As a result of Nuclear Regulatory Commission requirements, the Company has external trust funds for nuclear decommissioning costs; however, the Company currently has no additional funding requirements. For additional information, see Note 1 to the financial statements under “Nuclear Decommissioning.” In addition to the funds required for the Company’s construction program, approximately $550 million will be required by the end of 2011 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. 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, derivative obligations, preferred and preference stock dividends, leases, and other purchase commitments, are as follows. See Notes 1, 6, and 7 to the financial statements for additional information. 22 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2008 Annual Report Contractual Obligations Long-term debt(a) – Principal Interest Preferred and preference stock dividends(b) Energy-related derivative obligations(c) Operating leases Purchase commitments(d) – Capital (e) Limestone(f) Coal Nuclear fuel Natural gas (g) Purchased power Long-term service agreements(h) Postretirement benefits trust(i) Total 2009 $ 250 291 39 75 23 1,365 3 1,461 48 505 105 18 17 $4,200 2010- 2011 $ 300 549 79 20 28 1,865 24 1,804 82 386 44 35 35 $5,251 2012- 2013 (in millions) $ 750 499 79 - 12 After 2013 Total $ 4,558 4,351 - - 11 $ 5,858 5,690 197 95 74 - 29 1,110 76 311 - 29 - $2,895 - 68 1,414 10 210 - 37 - 3,230 124 5,789 216 1,412 149 119 52 $10,659 $23,005 (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 1, 2009, 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) Preferred and preference stock do not mature; therefore, amounts are provided for the next five years only. (c) For additional information, see Notes 1 and 6 to the financial statements. (d) The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for 2008, 2007, and 2006 were $1.26 billion, $1.19 billion, and $1.10 billion, 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 nuclear fuel. At December 31, 2008, significant purchase commitments were outstanding in connection with the construction program. (f) As part of the Company’s program to reduce sulfur dioxide emissions from certain of its coal plants, the Company has begun construction of flue gas desulfurization projects and has entered into various long-term commitments for the procurement of limestone to be used in such equipment. (g) 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, 2008. (h) Long-term service agreements include price escalation based on inflation indices. (i) The Company forecasts postretirement trust contributions over a three-year period. The Company expects that the earliest that cash may have to be contributed to the pension trust fund is 2011 and such contribution could be significant; however, projections of the amount vary significantly depending on interpretations of and decisions related to federal legislation passed during 2008 as well as other key variables including future trust fund performance and cannot be determined at this time. Therefore, no amounts related to the pension trust are included in the table. 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. 23 MANAGEMENT’S DISCUSSION AND ANALYSIS (Continued) Alabama Power Company 2008 Annual Report Cautionary Statement Regarding Forward-Looking Statements The Company’s 2008 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, fuel cost recovery and other rate actions, environmental regulations and expenditures, access to sources of capital, projections for postretirement benefit and nuclear decommissioning trust contributions, financing activities, completion of construction projects, filings with state and federal regulatory authorities, impacts of adoption of new accounting rules, estimated sales and purchases under new power sale and purchase agreements, 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, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, or particulate matter and other substances, and also changes in 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 FERC matters and the pending EPA civil action against the Company; the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates; variations in demand for electricity, including those relating to weather, the general economy, population and business growth (and declines), and the effects of energy conservation measures; available sources and costs of fuels; effects of inflation; 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 actions relating to fuel and storm restoration 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 and to perform as required; 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, droughts, pandemic health events such as an avian influenza, 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 SEC. The Company expressly disclaims any obligation to update any forward-looking statements. 24 STATEMENTS OF INCOME For the Years Ended December 31, 2008, 2007, and 2006 Alabama Power Company 2008 Annual Report Operating Revenues: Retail revenues Wholesale revenues -- Non-affiliates Affiliates Other revenues Total operating revenues Operating Expenses: Fuel Purchased power -- Non-affiliates Affiliates Other operations and maintenance Depreciation and amortization Taxes other than income taxes Total operating expenses Operating Income Other Income and (Expense): Allowance for equity funds used during construction Interest income Interest expense, net of amounts capitalized Other income (expense), net Total other income and (expense) Earnings Before Income Taxes Income taxes Net Income Dividends on Preferred and Preference Stock Net Income After Dividends on Preferred and Preference Stock The accompanying notes are an integral part of these financial statements. 2008 2007 (in thousands) 2006 $4,862,281 $4,406,956 $3,995,731 711,903 308,482 194,265 6,076,931 627,047 144,089 181,901 5,359,993 634,552 216,028 168,417 5,014,728 2,184,310 1,762,418 1,672,831 178,807 359,202 1,258,888 520,449 306,522 4,808,178 1,268,753 45,519 19,394 (278,917) (31,514) (245,518) 1,023,235 367,813 655,422 39,463 $ 615,959 96,928 341,461 1,186,235 471,536 286,579 4,145,157 1,214,836 35,425 19,545 (273,737) (29,144) (247,911) 966,925 351,198 615,727 36,145 $ 579,582 124,022 302,045 1,096,978 451,018 258,135 3,905,029 1,109,699 18,253 20,897 (252,282) (23,758) (236,890) 872,809 330,345 542,464 24,734 $ 517,730 25 STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2008, 2007, and 2006 Alabama Power Company 2008 Annual Report Operating Activities: Net income Adjustments to reconcile net income to net cash provided from operating activities -- Depreciation and amortization Deferred income taxes and investment tax credits, net Allowance for equity funds used during construction Pension, postretirement, and other employee benefits Stock based compensation expense Tax benefit of stock options Other, net Changes in certain current assets and liabilities -- Receivables Fossil fuel stock Materials and supplies Other current assets Accounts payable Accrued taxes Accrued compensation Other current liabilities Net cash provided from operating activities Investing Activities: Property additions Investment in restricted cash from pollution control bonds Distribution of restricted cash from pollution control bonds Nuclear decommissioning trust fund purchases Nuclear decommissioning trust fund sales Cost of removal net of salvage Other Net cash used for investing activities Financing Activities: Increase (decrease) in notes payable, net Proceeds -- Senior notes Preferred and preference stock Common stock issued to parent Capital contributions Gross excess tax benefit of stock options Pollution control revenue bonds Redemptions -- Senior notes Preferred stock Pollution control revenue bonds Other long-term debt Payment of preferred and preference stock dividends Payment of common stock dividends Other Net cash provided from financing activities Net Change in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Year Cash and Cash Equivalents at End of Year Supplemental Cash Flow Information: Cash paid during the period for -- 2008 2007 (in thousands) 2006 $ 655,422 $ 615,727 $ 542,464 599,767 126,538 (45,519) (26,530) 3,105 685 27,689 (31,693) (134,212) (17,723) (1,494) (8,751) 36,957 (4,722) (198) 1,179,321 (1,477,643) (96,326) 35,979 (300,503) 299,636 (41,744) (19,143) (1,599,744) 548,959 21,269 (35,425) (18,781) 4,900 1,118 (13,650) (5,797) (33,840) (32,543) 22,354 78,508 (17,248) 4,194 10,098 1,149,843 (1,157,186) (97,775) 78,043 (334,275) 333,409 (48,932) (26,621) (1,253,337) 524,313 (27,562) (18,253) (15,196) 4,848 610 29,564 (33,260) (28,179) (25,711) 38,645 (49,725) 1,124 (6,157) 18,486 956,011 (933,306) - - (286,551) 285,685 (40,834) (1,777) (976,783) 24,995 (119,670) (195,609) 850,000 - 300,000 21,272 1,289 265,100 (410,000) (125,000) (11,100) - (40,899) (491,300) (9,369) 374,988 (45,435) 73,616 28,181 $ 850,000 200,000 229,000 27,867 2,556 265,500 (668,500) - - (103,093) (31,380) (465,000) (25,709) 161,571 58,077 15,539 73,616 $ 950,000 150,000 120,000 27,160 1,291 - (546,500) - (2,950) - (24,318) (440,600) (24,635) 13,839 (6,933) 22,472 15,539 $ Interest (net of $20,215, $17,961, and $7,930 capitalized, respectively) Income taxes (net of refunds) $258,918 214,368 $248,289 340,951 $245,387 345,803 The accompanying notes are an integral part of these financial statements. 26 BALANCE SHEETS At December 31, 2008 and 2007 Alabama Power Company 2008 Annual Report Assets Current Assets: Cash and cash equivalents Restricted cash Receivables -- Customer accounts receivable Unbilled revenues Under recovered regulatory clause revenues Other accounts and notes receivable Affiliated companies Accumulated provision for uncollectible accounts Fossil fuel stock, at average cost Materials and supplies, at average cost Vacation pay Prepaid expenses Other Total current assets Property, Plant, and Equipment: In service Less accumulated provision for depreciation Nuclear fuel, at amortized cost Construction work in progress Total property, plant, and equipment Other Property and Investments: Equity investments in unconsolidated subsidiaries Nuclear decommissioning trusts, at fair value Other Total other property and investments Deferred Charges and Other Assets: Deferred charges related to income taxes Prepaid pension costs Deferred under recovered regulatory clause revenues Other regulatory assets Other Total deferred charges and other assets Total Assets The accompanying notes are an integral part of these financial statements. 27 2008 (in thousands) 2007 $ 28,181 80,079 $ 73,616 19,732 350,409 98,921 153,899 44,645 70,612 (8,882) 322,089 305,880 52,577 88,220 87,740 1,674,370 17,635,129 6,259,720 11,375,409 231,862 1,092,516 12,699,787 50,912 403,966 62,782 517,660 362,596 166,334 180,874 732,367 202,018 1,644,189 $16,536,006 357,355 95,278 232,226 42,745 61,250 (7,988) 182,963 287,994 50,266 72,952 19,610 1,487,999 16,669,142 5,950,373 10,718,769 137,146 928,182 11,784,097 48,664 542,846 31,146 622,656 347,193 989,085 81,650 224,792 209,153 1,851,873 $15,746,625 2008 (in thousands) 2007 $ 250,079 24,995 $ 535,152 - 178,708 358,176 77,205 18,299 30,372 56,375 44,217 91,856 83,873 53,777 1,267,932 5,604,791 2,243,117 90,083 172,638 396,923 461,284 634,792 79,150 45,859 4,123,846 10,996,569 685,127 4,854,310 $16,536,006 193,518 308,177 67,722 45,958 29,198 55,263 42,138 92,385 6,404 48,927 1,424,842 4,750,196 2,065,264 93,709 180,578 349,974 505,794 613,616 637,040 31,417 4,477,392 10,652,430 683,512 4,410,683 $15,746,625 BALANCE SHEETS At December 31, 2008 and 2007 Alabama Power Company 2008 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 Liabilities from risk management activities Other Total current liabilities Long-term Debt (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 Preferred and Preference Stock (See accompanying statements) Common Stockholder's Equity (See accompanying statements) Total Liabilities and Stockholder's Equity Commitments and Contingent Matters (See notes) The accompanying notes are an integral part of these financial statements. 28 STATEMENTS OF CAPITALIZATION At December 31, 2008 and 2007 Alabama Power Company 2008 Annual Report Long-Term Debt: Long-term debt payable to affiliated trusts -- 5.5% due 2042 Long-term notes payable -- 3.125% to 5.375% due 2008 Floating rate (2.34% at 1/1/09) due 2009 4.70% due 2010 5.10% due 2011 4.85% due 2012 5.80% due 2013 5.125% to 6.375% due 2016-2047 Total long-term notes payable Other long-term debt -- Pollution control revenue bonds: 2.00% to 5.00% due 2030-2038 Variable rates (0.92% to 1.83% at 1/1/09) due 2015-2036 Total other long-term debt Capitalized lease obligations Unamortized debt premium (discount), net Total long-term debt (annual interest requirement -- $290.8 million) Less amount due within one year Long-term debt excluding amount due within one year 2008 2007 (in thousands) 2008 (percent of total) 2007 $ 206,186 $ 206,186 - 250,000 100,000 200,000 500,000 250,000 3,275,000 4,575,000 500,500 576,190 1,076,690 79 (3,085) 5,854,870 250,079 5,604,791 410,000 250,000 100,000 200,000 200,000 - 2,975,000 4,135,000 - 822,690 822,690 231 (3,759) 5,160,348 410,152 4,750,196 50.3% 48.3% 29 STATEMENTS OF CAPITALIZATION (continued) At December 31, 2008 and 2007 Alabama Power Company 2008 Annual Report Preferred and Preference Stock: Cumulative preferred stock $100 par or stated value -- 4.20% to 4.92% Authorized - 3,850,000 shares Outstanding - 475,115 shares $1 par value -- 5.20% to 5.83% Authorized - 27,500,000 shares Outstanding - 12,000,000 shares: $25 stated value Outstanding - 2008: 0 shares 2007: 1,250 shares: $100,000 stated capital Preference stock Authorized - 40,000,000 shares Outstanding - $1 par value -- 5.63% to 6.50% - 14,000,000 shares (non-cumulative) $25 stated value Total preferred and preference stock (annual dividend requirement -- $39.5 million) Less amount due within one year Preferred and preference stock excluding amount due within one year Common Stockholder's Equity: Common stock, par value $40 per share -- Authorized - 2008: 40,000,000 shares - 2007: 25,000,000 shares Outstanding - 2008: 25,475,000 shares - 2007: 17,975,000 shares Paid-in capital Retained earnings Accumulated other comprehensive income (loss) Total common stockholder's equity Total Capitalization The accompanying notes are an integral part of these financial statements. 2008 2007 (in thousands) 2008 (percent of total) 2007 47,610 47,610 294,105 - 294,105 123,331 343,412 343,466 685,127 - 808,512 125,000 685,127 683,512 6.1 6.9 1,019,000 719,000 2,091,462 1,753,797 (9,949) 4,854,310 $11,144,228 2,065,298 1,630,832 (4,447) 4,410,683 $9,844,391 43.6 100.0% 100.0% 44.8 30 STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2008, 2007, and 2006 Alabama Power Company 2008 Annual Report Common Stock Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) (in thousands) $370,000 - 120,000 - - - - - 490,000 229,000 - - - - 719,000 Balance at December 31, 2005 Net income after dividends on preferred stock Issuance of common stock Capital contributions from parent company Other comprehensive income (loss) Adjustment to initially apply FASB Statement No. 158, net of tax Cash dividends on common stock Other Balance at December 31, 2006 Net income after dividends on preferred and preference stock Issuance of common stock Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Other Balance at December 31, 2007 Net income after dividends on preferred and preference stock Issuance of common stock Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Other Balance at December 31, 2008 The accompanying notes are an integral part of these financial statements. - 300,000 - - - - $1,019,000 - - 579,582 $1,995,056 - - 33,907 - - - - 2,028,963 $1,439,144 517,730 - - - - (440,600) (29) 1,516,245 - 36,441 - - (106) 2,065,298 - - 26,164 - - - $2,091,462 - - - (465,000) 5 1,630,832 615,959 - - - (491,300) (1,694) $1,753,797 $(11,474) - - - (4,057) 12,610 - - (2,921) - - - (1,526) - - (4,447) - - - (5,502) - - $( 9,949) Total $3,792,726 517,730 120,000 33,907 (4,057) 12,610 (440,600) (29) 4,032,287 579,582 229,000 36,441 (1,526) (465,000) (101) 4,410,683 615,959 300,000 26,164 (5,502) (491,300) (1,694) $4,854,310 STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2008, 2007, and 2006 Alabama Power Company 2008 Annual Report Net income after dividends on preferred and preference stock Other comprehensive income (loss): Qualifying hedges: Changes in fair value, net of tax of $(4,297), $(1,226), and $155, respectively Reclassification adjustment for amounts included in net income, net of tax of $952, $298, and $(3,696), respectively Pension and other postretirement benefit plans: Change in additional minimum pension liability, net of tax of $-, $-, and $1,109, respectively Total other comprehensive income (loss) Comprehensive Income The accompanying notes are an integral part of these financial statements. 31 2008 2007 (in thousands) 2006 $615,959 $579,582 $517,730 (7,068) (2,017) 1,566 491 - (5,502) $610,457 - (1,526) $578,056 255 (6,080) 1,768 (4,057) $513,673 NOTES TO FINANCIAL STATEMENTS Alabama Power Company 2008 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 four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – the Company, Georgia Power Company (Georgia Power), Gulf Power Company (Gulf Power), and Mississippi Power Company (Mississippi Power). The Company provides 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, acquires, owns, and manages generation assets, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in leveraged leases and various other energy-related businesses. The investments in synthetic fuels ended on December 31, 2007. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants, including the Company’s Plant Farley. 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. The Company is subject to regulation by the Federal Energy Regulatory Commission (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. Reclassifications Certain prior years’ data presented in the financial statements have been reclassified to conform with current year presentation. The statements of cash flows for the prior periods presented have been modified within the operating activities section to combine the amount of “Deferred revenues” and “Hedge settlements” into “Other, net.” The statements of income for the prior periods presented have been modified within the operating expenses section to combine the line items “Other operations” and “Maintenance” into a single line item entitled “Other operations and maintenance.” The balance sheet at December 31, 2007 was modified to present a separate line for “Liabilities for risk management activities” previously included in “Other.” These reclassifications had no effect on total assets, cash flows, or net income. 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, digital wireless communications, and other services with respect to business and operations and power pool transactions. Costs for these services amounted to $321 million, $299 million, and $266 million during 2008, 2007, and 2006, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. 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 32 NOTES (continued) Alabama Power Company 2008 Annual Report 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 $196 million, $182 million, and $162 million during 2008, 2007, and 2006, 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 non-fuel expenses which were $11.1 million in 2008, $9.8 million in 2007, and $8.6 million in 2006. See Note 4 for additional information. Southern Company’s 30% ownership interest in Alabama Fuel Products, LLC (AFP), which produced synthetic fuel was terminated in July 2006. The Company had an agreement with an indirect subsidiary of Southern Company that provided services for AFP. Under this agreement, the Company provided certain accounting functions, including processing and paying fuel transportation invoices, and the Company was reimbursed for its expenses. Amounts billed under this agreement totaled approximately $1.2 million, $58.1 million, and $56.5 million in 2008, 2007, and 2006, respectively. In addition, the Company purchased synthetic fuel from AFP for use at several of the Company’s plants. Synthetic fuel purchases totaled $6.2 million, $462.1 million, and $446.6 million in 2008, 2007, and 2006, respectively. The synthetic fuel purchases and related party transactions were terminated as of December 31, 2007. The Company had an agreement with Southern Power under which the Company operated and maintained Plant Harris at cost. On August 1, 2007, that agreement was terminated and replaced with a service agreement under which the Company provides to Southern Power specifically requested services. In 2008, 2007, and 2006, the Company billed Southern Power $0.9 million, $2.4 million, and $2.2 million, respectively, under these agreements. Under a power purchase agreement (PPA) with Southern Power, the Company’s purchased power costs from Plant Harris in 2008, 2007, and 2006 totaled $63.2 million, $66.3 million, and $61.7 million, respectively. The Company also provides the fuel, at cost, associated with the PPA and the fuel cost recognized by the Company was $119.6 million in 2008, $108.1 million in 2007, and $77.8 million in 2006. 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, 2008, 2007 and 2006. See Note 3 under “Retail Regulatory Matters” and Note 7 under “Purchased Power Commitments” for additional information. Also, see Note 4 for information regarding the Company’s ownership in and PPA with Southern Electric Generating Company (SEGCO). In the second quarter, Southern Power sold a turbine rotor assembly to the Company for approximately $8.2 million. In October 2008, the Company also sold a rotor to Southern Power for approximately $6.3 million and sold a distance piece component to Gulf Power for approximately $0.3 million. In the fourth quarter, the Company purchased from SEGCO two 230kV transmission lines. The purchase price for the transmission line facilities was approximately $3.9 million. These affiliate transactions were made in accordance with FERC and Alabama PSC rules and guidelines. The traditional 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. 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” (SFAS No. 71). 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. 33 NOTES (continued) Alabama Power Company 2008 Annual Report Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: 2008 2007 Note (in millions) Deferred income tax charges Loss on reacquired debt Vacation pay Under recovered regulatory clause revenues Fuel-hedging (realized and unrealized) losses Other assets Asset retirement obligations Other cost of removal obligations Deferred income tax credits Fuel-hedging (realized and unrealized) gains Mine reclamation and remediation Nuclear outage Deferred purchased power Natural disaster reserve (future storms) Other liabilities Overfunded retiree benefit plans Underfunded retiree benefit plans Total assets (liabilities), net $ 363 80 53 335 95 7 18 (635) (90) (4) (14) (8) (20) (33) (4) - 614 $757 $ 347 87 50 314 6 6 (150) (614) (94) (5) (14) 2 (20) (26) (3) (423) 138 $ (399) (a) (b) (c) (d) (e) (d) (a) (a) (a) (e) (d) (d) (d) (d) (d) (f) (f) 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) Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. (d) Recorded and recovered or amortized as approved or accepted by the Alabama PSC. (e) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally does not exceed two years. Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clauses. (f) Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information. In the event that a portion of the Company’s operations is no longer subject to the provisions of SFAS No. 71, the Company would be required to write off or reclassify to accumulated other comprehensive income 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, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. Revenues Energy and other revenues are recognized as services are provided. Wholesale 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 balances and files for revised rates as required or when management deems appropriate depending on the rate. See Note 3 under “Retail Regulatory Matters – Fuel Cost Recovery” for additional information. The Company has a diversified base of customers. No single customer comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than one percent of revenues. 34 NOTES (continued) Alabama Power Company 2008 Annual Report Fuel Costs 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. See Note 3 under “Nuclear Fuel Disposal Costs” for additional information. Income and Other 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. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. In accordance with FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), the Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information. 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. The Company’s property, plant, and equipment consisted of the following at December 31: Generation Transmission Distribution General Plant acquisition adjustment Total plant in service (in millions) 2008 $ 9,096 2,559 4,827 1,141 12 $17,635 2007 $ 8,541 2,435 4,586 1,095 12 $16,669 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 nuclear refueling costs in advance of the unit’s next refueling outage. The refueling cycle is 18 months for each unit. During 2008, the Company accrued $39.4 million and paid $28.5 million for an outage at Plant Farley Unit 2. At December 31, 2008, the reserve balance totaled $8.7 million and is included in the balance sheet in other regulatory liabilities. Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.2% in 2008 and 3.1% in 2007 and 2006. Depreciation studies are conducted periodically to update the composite rates and the information is provided to the Alabama PSC and approved by the FERC. 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. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. 35 NOTES (continued) Alabama Power Company 2008 Annual Report Asset Retirement Obligations and Other Costs of Removal Asset retirement obligations are computed as the present value of the ultimate costs for an asset’s future retirement and are 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. 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. 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, 2008 was $404 million. In addition, the Company has retirement obligations related to various landfill sites and underground storage tanks, asbestos removal, and disposal of polychlorinated biphenyls in certain transformers. The Company also has 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 differences between costs recognized under Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” 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. See “Nuclear Decommissioning” for further information on amounts included in rates. Details of the asset retirement obligations included in the balance sheets are as follows: 2008 2007 (in millions) Balance beginning of year Liabilities incurred Liabilities settled Accretion Cash flow revisions (a) Balance end of year (a) Updated based on results from 2008 Nuclear Decommissioning Study $506 - (2) 31 (74) $461 $476 - (3) 33 - $506 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 an external trust fund (the Fund) to comply with the NRC’s regulations. Use of the Fund is restricted to nuclear decommissioning activities and the Fund is 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 Fund is invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as of December 31, 2008 as trading securities pursuant to FASB Statement No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS No. 115). On January 1, 2008, the Company adopted FASB Statement No. 159, “Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115” (SFAS No. 159). This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. The Company elected the fair value option only for investment securities held in the Fund. The Fund is included in the balance sheets at fair value, as disclosed in Note 10. Management elected to continue to record the Fund at fair value because management believes that fair value best represents the nature of the Fund. Management has delegated day-to-day management of the investments in the Fund to unrelated third party managers with oversight by Company management. The managers of the Fund are authorized, within broad limits, to actively buy and sell securities at their own discretion in order to maximize the investment return on the Fund investments. Because of the Company’s inability to choose to hold securities that have experienced unrealized losses until recovery of their value, all unrealized losses incurred during 2006 and 2007, prior to the adoption of SFAS No. 159, were considered other-than-temporary impairments under SFAS No. 115. 36 NOTES (continued) Alabama Power Company 2008 Annual Report The adoption of SFAS No. 159 had no impact on the results of operations, cash flows, or financial condition of the Company. For all periods presented, all gains and losses, whether realized, unrealized, or identified as other-than-temporary, have been and will continue to be recorded in the regulatory liability for asset retirement obligations in the balance sheets and are not included in net income or other comprehensive income. Fair value adjustments, realized gains, and other-than-temporary impairment losses are determined on a specific identification basis. At December 31, 2008, investment securities in the Fund totaled $402.9 million consisting of equity securities of $256.7 million, debt securities of $135.3 million, and $10.9 million of other securities. These amounts exclude receivables related to investment income and pending investment sales, and payables related to pending investment purchases. At December 31, 2007, investment securities in the Fund totaled $542.8 million consisting of equity securities of $385.4 million, debt securities of $140.2 million, and $17.2 million of other securities. Unrealized gains were $130.8 million for equity securities, $7.0 million debt securities, and $0.1 million for other securities. Other-than-temporary impairments were $(15.7) million for equity securities and $(3.5) million for debt securities. Sales of the securities held in the Fund resulted in cash proceeds of $299.6 million, $333.4 million, and $285.7 million, in 2008, 2007, and 2006, respectively, all of which were re-invested. For 2008, fair value reductions, including reinvested interest and dividends, were $134.4 million, of which $107.6 million related to securities held in the Fund at December 31, 2008. Realized gains and other- than-temporary impairment losses were $34.6 million and $37.2 million, respectively, in 2007 and $22.0 million and $18.2 million, respectively, in 2006. While the investment securities held in the Fund are reported as trading securities from the perspective of SFAS No. 115, the Fund continues to be managed with a long-term focus. Accordingly, all purchases and sales within the Fund are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of and purpose for which the securities were acquired. Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the Alabama PSC. 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 a plan 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, 2008, the accumulated provisions for decommissioning were as follows: External trust funds Internal reserves Total (in millions) $404 26 $430 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 2008 for Plant Farley was as follows: Decommissioning periods: Beginning year Completion year Site study costs: Radiated structures Non-radiated structures Total 2037 2065 (in millions) $1,060 72 $1,132 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. For ratemaking purposes, the Company’s decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and a trust earnings rate of 7.0%. 37 NOTES (continued) Alabama Power Company 2008 Annual Report Amounts previously contributed to the external trust fund are currently projected to be adequate to meet the decommissioning obligations. 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 Company continues to transfer 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, which 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. The equity component of AFUDC is not included in calculating taxable income. All current construction costs are included in retail rates. The composite rate used to determine the amount of AFUDC was 9.2% in 2008, 9.4% in 2007, and 8.8% in 2006. AFUDC, net of income tax, as a percent of net income after dividends on preferred and preference stock was 9.4% in 2008, 8.0% in 2007, and 4.5% in 2006. 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 an 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 an 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 loss 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 is authorized to collect a monthly NDR charge per account that consists of two components which began on 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 within three years assuming the Company experiences no additional storms. The second component of the NDR charge is intended to allow recovery of any existing deferred hurricane related operations and maintenance costs and any future reserve deficits over a 24-month period. 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. Absent further Alabama PSC approval, 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. At December 31, 2008, the Company had accumulated a balance of $33.2 million in the target reserve for future storms, which is included in the balance sheets under “Other Regulatory Liabilities.” In June 2007, the Company fully recovered its prior storm cost of $51.3 million resulting from Hurricanes Dennis and Katrina. As a result, customer rates decreased by this portion of the NDR charge effective July 1, 2007. As revenue from the NDR charge is recognized, an equal amount of operations 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 annual cash flow. 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. 38 NOTES (continued) Alabama Power Company 2008 Annual Report 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 expensed or capitalized to plant, as appropriate, at weighted average cost when installed. Fuel Inventory Fuel inventory includes the average costs of oil, coal, natural gas, and emission allowances. Fuel is charged to inventory when purchased and then expensed as used and recovered by the Company through fuel cost recovery rates approved by the Alabama PSC. Emission allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost. 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 (categorized in “Other” or shown separately as “Risk Management Activities”) and are measured at fair value. See Note 10 for additional information. 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. See Note 6 under “Financial Instruments” for additional information. The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company has no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2008. 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. The Company’s other financial instruments for which the carrying amounts did not equal fair values at December 31 were as follows: Long-term debt: 2008 2007 Carrying Amount Fair Value (in millions) $5,855 5,160 $5,784 5,079 The fair values were based on either closing market prices (Level 1) or closing prices of comparable instruments (Level 2). See Note 10 for all other items recognized at fair value in the financial statements. 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 prior to the adoption of SFAS No.158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS No. 158), the 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 “Long-Term Debt Payable to Affiliated Trusts” for additional information. However, the Company is not considered the primary beneficiary of the trusts. Therefore, the investments in 39 NOTES (continued) Alabama Power Company 2008 Annual Report these trusts are reflected as Other Investments, and the related loans from the trusts are included in Long-term Debt in the balance sheets. 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 $0.4 million and $2.3 million at December 31, 2008 and 2007, 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). No contributions to the plan are expected for the year ending December 31, 2009. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds trusts to the extent required by the Alabama PSC and the FERC. For the year ending December 31, 2009, postretirement trust contributions are expected to total approximately $17.2 million. The measurement date for plan assets and obligations for 2008 was December 31 while the measurement date for prior years was September 30. Pursuant to SFAS No. 158, the Company was required to change the measurement date for its defined benefit postretirement plans from September 30 to December 31 beginning with the year ended December 31, 2008. As permitted, the Company adopted the measurement date provisions of SFAS No. 158 effective January 1, 2008 resulting in an increase in long-term liabilities of approximately $5 million and an increase in prepaid pension costs of approximately $11 million. Pension Plans The total accumulated benefit obligation for the pension plans was $1.4 billion in 2008 and $1.3 billion in 2007. Changes during the 15-month period ended December 31, 2008 and 12-month period ended September 30, 2007 in the projected benefit obligations and the fair value of plan assets were as follows: 2008 2007 (in millions) Change in benefit obligation Benefit obligation at beginning of year Service cost Interest cost Benefits paid Plan amendments Actuarial (gain) loss Balance at end of year Change in plan assets Fair value of plan assets at beginning of year Actual return (loss) on plan assets Employer contributions Benefits paid Fair value of plan assets at end of year Funded status at end of year Fourth quarter contributions Prepaid pension asset, net $1,420 43 109 (94) - (18) 1,460 2,318 (692) 7 (94) 1,539 79 - $ 79 $1,394 35 82 (70) 10 (31) 1,420 2,038 346 4 (70) 2,318 898 2 $ 900 40 NOTES (continued) Alabama Power Company 2008 Annual Report At December 31, 2008, the projected benefit obligations for the qualified and non-qualified pension plans were $1.4 billion and $87 million, respectively. All pension plan assets are related to the qualified pension plan. 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. 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. The actual composition of the Company’s pension plan assets as of the end of year, along with the targeted mix of assets, is presented below: Domestic equity International equity Fixed income Real estate Private equity Total Target 36% 24 15 15 10 100% 2008 34% 23 14 19 10 100% 2007 38% 24 15 16 7 100% Amounts recognized in the balance sheets related to the Company’s pension plans consist of: Prepaid pension asset Other regulatory assets Current liabilities, other Other regulatory liabilities Employee benefit obligations 2008 (in millions) $166 479 (6) - (81) 2007 $ 989 43 (5) (423) (84) Presented below are the amounts included in regulatory assets and regulatory liabilities at December 31, 2008 and 2007 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2009: Balance at December 31, 2008: Regulatory assets Regulatory liabilities Total Balance at December 31, 2007: Regulatory assets Regulatory liabilities Total Estimated amortization in net periodic pension cost in 2009: Regulatory assets Regulatory liabilities Total Prior Service Cost Net(Gain)Loss (in millions) $58 - $58 $14 56 $70 $ 9 - $ 9 $ 421 - $ 421 $ 29 (479) $ (450) $ $ 1 - 1 41 NOTES (continued) Alabama Power Company 2008 Annual Report The changes in the balances of regulatory assets and regulatory liabilities related to the defined benefit pension plans for the 15-month period ended December 31, 2008 and the 12-month period ended September 30, 2007 are presented in the following table: Regulatory Assets Regulatory Liabilities (in millions) Balance at December 31, 2006 Net (gain) loss Change in prior service costs Reclassification adjustments: Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2007 Net (gain) loss Change in prior service costs Reclassification adjustments: Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2008 $36 1 10 (2) (2) (4) 7 43 441 - (2) (3) (5) 436 $479 $(183) (232) - (8) - (8) (240) (423) 433 - (10) - (10) 423 - $ Components of net periodic pension cost (income) were as follows: Service cost Interest cost Expected return on plan assets Recognized net (gain) loss Net amortization Net periodic pension (income) 2008 $ 35 87 (160) 2 10 $ (26) 2007 (in millions) $ 35 82 (146) 2 10 $ (17) 2006 $ 37 77 (139) 3 9 $ (13) Net periodic pension cost (income) is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market- related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets. Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2008, estimated benefit payments were as follows: 2009 2010 2011 2012 2013 2014 to 2018 Benefit Payments (in millions) $ 81 84 88 92 96 556 42 NOTES (continued) Alabama Power Company 2008 Annual Report Other Postretirement Benefits Changes during the 15-month period ended December 31, 2008 and the 12-month period ended September 30, 2007 in the accumulated postretirement benefit obligations (APBO) and in the fair value of plan assets were as follows: Change in benefit obligation Benefit obligation at beginning of year Service cost Interest cost Benefits paid Actuarial (gain) loss Retiree drug subsidy Balance at end of year Change in plan assets Fair value of plan assets at beginning of year Actual return (loss) on plan assets Employer contributions Benefits paid Fair value of plan assets at end of year Funded status at end of year Fourth quarter contributions Accrued liability 2008 2007 (in millions) $ 480 9 37 (30) (53) 3 446 297 (75) 57 (27) 252 (194) - $(194) $ 490 7 28 (23) (24) 2 480 259 36 23 (21) 297 (183) 28 $(155) Other postretirement benefit 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. 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. The actual composition of the Company’s other postretirement benefit plan assets as of the end of year, along with the targeted mix of assets, is presented below: Domestic equity International equity Fixed income Real estate Private equity Total Target 49% 12 31 5 3 100% 2008 31% 13 46 7 3 100% 2007 46% 15 29 7 3 100% Amounts recognized in the balance sheets related to the Company’s other postretirement benefit plans consist of: Regulatory assets Employee benefit obligations 2008 2007 (in millions) $ 135 (194) $ 95 (155) 43 NOTES (continued) Alabama Power Company 2008 Annual Report Presented below are the amounts included in regulatory assets at December 31, 2008 and 2007, related to the other postretirement benefit plans that had not yet been recognized in net periodic postretirement benefit cost along with the estimated amortization of such amounts for 2009. Balance at December 31, 2008: Regulatory asset Balance at December 31, 2007: Regulatory asset Estimated amortization as net periodic postretirement cost in 2009: Regulatory asset Prior Service Cost Net (Gain)Loss (in millions) Transition Obligation $49 $55 $ 4 $71 $20 $15 $20 $ - $ 4 The change in the balance of regulatory assets related to the other postretirement benefit plans for the 15-month period ended December 31, 2008 and the 12-month period ended September 30, 2007 are presented in the following table: Balance at December 31, 2006 Net gain Change in prior service costs Reclassification adjustments: Amortization of transition obligation Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2007 Net loss Change in prior service costs Reclassification adjustments: Amortization of transition obligation Amortization of prior service costs Amortization of net gain Total reclassification adjustments Total change Balance at December 31, 2008 Regulatory Assets (in millions) $147 (41) - (4) (5) (2) (11) (52) 95 50 - (5) (5) - (10) 40 $135 Components of the other postretirement benefit plans’ net periodic cost were as follows: Service cost Interest cost Expected return on plan assets Net amortization Net postretirement cost 2008 $ 7 29 (22) 9 $ 23 2007 (in millions) $ 7 28 (19) 11 $ 27 2006 $ 7 26 (17) 12 $ 28 The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced the Company’s expenses for the years ended December 31, 2008, 2007, and 2006 by approximately $10.7 million, $10.7 million, and $11.1 million, respectively. 44 NOTES (continued) Alabama Power Company 2008 Annual Report Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the postretirement plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows: 2009 2010 2011 2012 2013 2014 to 2018 Benefit Payments $ 28 31 33 35 36 196 Subsidy Receipts (in millions) $ (3) (3) (4) (4) (5) (30) Total $ 25 28 29 31 31 166 Actuarial Assumptions The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2005 for the 2006 plan year, using a discount rate of 5.50%. Discount Annual salary increase Long-term return on plan assets 2008 6.75% 3.75 8.50 2007 6.30% 3.75 8.50 2006 6.00% 3.50 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. An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 9.15% for 2009, decreasing gradually to 5.50% through the year 2015, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2008 as follows: Benefit obligation Service and interest costs 1 Percent Increase 1 Percent Decrease (in millions) $31 2 $33 2 Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution up to 6% of an employee’s base salary. Prior to November 2006, the Company matched employee contributions at a rate of 75% up to 6% of the employee’s base salary. Total matching contributions made to the plan for 2008, 2007, and 2006 were $18 million, $17 million, and $14 million, respectively. 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, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water 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 current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements. 45 NOTES (continued) Alabama Power Company 2008 Annual Report Environmental Matters New Source Review Actions In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including the Company, alleging that it had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against the Company in the U.S. District Court for the Northern District of Alabama after the Company was dismissed from the original action. In this lawsuit, the EPA alleged that NSR violations occurred at five coal-fired generating facilities operated by the Company. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between the Company and the EPA, resolving a portion of the Company’s lawsuit relating to the alleged NSR violations at Plant Miller. The consent decree required the Company to pay $100,000 to resolve the government’s claim for a civil penalty and to donate $4.9 million of sulfur dioxide emission allowances to a nonprofit charitable organization. It also formalized specific emissions reductions to be accomplished by the Company, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in Alabama granted the Company’s motion for summary judgment and entered final judgment in favor of the Company on the EPA’s claims related to all of the remaining plants: Plants Barry, Gaston, Gorgas, and Greene County. The plaintiffs appealed the district court’s decision to the U.S. Court of Appeals for the Eleventh Circuit, where the appeal was stayed, pending the U.S. Supreme Court’s decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke Energy case in April 2007, and in December 2007, the Eleventh Circuit vacated the district court’s decision in the Company’s case and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court’s decision in the Duke Energy case. On July 24, 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of the Company regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. The decision did not resolve the case and the ultimate outcome of this matter cannot be determined at this time. 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 $37,500 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 or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Carbon Dioxide Litigation New York Case In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. 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. The plaintiffs have not, however, requested that damages be awarded in 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 in October 2005, but no decision has been issued. The ultimate outcome of these matters cannot be determined at this time. 46 NOTES (continued) Alabama Power Company 2008 Annual Report Kivalina Case On February 26, 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. On June 30, 2008, all defendants filed motions to dismiss this case. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. The ultimate outcome of this matter cannot be determined at this time. Environmental Remediation The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. The Company has received authority from the Alabama PSC to recover approved environmental compliance costs through a specific retail rate clause that is adjusted annually. See “Retail Regulatory Matters – Rate CNP” herein for additional information. FERC Matters Market-Based Rate Authority The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. 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 the proceeding. Any new market-based rate sales by the Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level. In November 2007, the presiding administrative law judge issued an initial decision regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the Company 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, and could also result in total refunds of up to $3.9 million, plus interest. The Company believes that there is no meritorious basis for an adverse decision in this proceeding and is vigorously defending itself in this matter. In June 2007, the FERC issued its final rule in Order No. 697 regarding market-based rate authority. The FERC generally retained its current market-based rate standards. Responding to a number of requests for rehearing, the FERC issued Order No. 697-A on April 21, 2008 and Order No. 697-B on December 12, 2008. These orders largely affirmed the FERC’s prior revision and codification of the regulations governing market-based rates for public utilities. In accordance with the orders, Southern Company submitted to the FERC an updated market power analysis on September 2, 2008 related to its continued market-based rate authority. The ultimate outcome of this matter cannot now be determined. On October 17, 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On December 18, 2008, the FERC issued an order conditionally accepting the MBR tariff subject to certain revisions to the auction proposal. On January 21, 2009, Southern Company made a compliance filing that accepted all the conditions of the MBR tariff order. When this order becomes final, Southern Company will have 30 days to implement the wholesale auction. On December 31, 2008, the FERC issued an order conditionally accepting the CBR tariff subject to providing additional information concerning one aspect of the tariff. On January 30, 2009, Southern Company filed a response addressing the FERC inquiry to the CBR tariff order. Implementation of the energy auction in accordance with the MBR tariff order 47 NOTES (continued) Alabama Power Company 2008 Annual Report is expected to adequately mitigate going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory. The timing of when the FERC may issue the final orders on the MBR and CBR tariffs and the ultimate outcome of these matters cannot be determined at this time. Intercompany Interchange Contract The Company’s generation fleet is operated under the Intercompany Interchange Contract (IIC), as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies (including the Company), Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, (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. In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms and Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. In November 2006, Southern Company filed with the FERC a compliance plan in connection with the order. In April 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan did not have a material impact on the Company’s financial statements. In November 2007, Southern Company notified the FERC that the plan had been implemented. On December 12, 2008, the FERC division of audits issued, for public comment, its final audit report pertaining to compliance implementation and related matters. No comments challenging the audit report’s findings were submitted. A decision is now pending from the FERC. Generation Interconnection Agreements In November 2004, generator company subsidiaries of Tenaska, Inc. (Tenaska), as counterparties to two previously executed interconnection agreements with the Company, 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. No other similar complaints are pending with the FERC. In January 2007, the FERC issued an order granting Tenaska’s requested relief. Although the FERC’s order required the modification of Tenaska’s interconnection agreements, under the provisions of the order, the Company determined that no refund was payable to Tenaska. The Company requested rehearing asserting that the FERC retroactively applied a new principle to existing interconnection agreements. Tenaska requested rehearing of FERC’s methodology for determining the amount of refunds. The requested rehearings were denied and the Company and Tenaska have appealed the orders to the U.S. Circuit Court for the District of Columbia. The final outcome of this matter cannot now be determined. 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 retail common equity. Retail rates remain unchanged when the retail return on common equity ranges between 13.0% and 14.5%. In October 2005, the Alabama PSC approved a revision to 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% per year and any annual adjustment is limited to 5.0%. Prior to January 2007, annual adjustments were limited to 3.0%. Retail rates remain unchanged when the return on retail common equity is projected to be between 13.0% and 14.5%. 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 Rate RSE increase for 2008 was 3.24% or $147 million annually and was effective in January 2008. 48 NOTES (continued) Alabama Power Company 2008 Annual Report On October 7, 2008, the Alabama PSC approved a corrective rate package primarily providing for adjustments associated with customer charges to certain existing rate structures. This package, effective in January 2009, is expected to generate additional annual revenues of approximately $168 million. The Company agreed to a moratorium on any increase in rates in 2009 under Rate RSE. On December 1, 2008, the Company made its submission of projected data for calendar year 2009. Rate CNP The Company’s retail rates, approved by the Alabama PSC, 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 a Rate Certificated New Plant (Rate CNP). In April 2006, an annual adjustment to Rate CNP increased retail rates by approximately 0.5% or $19 million annually. There was no rate adjustment associated with the annual true-up adjustment in April 2007 and 2008. There will be no adjustment to the current Rate CNP to recover certificated PPA costs in April 2009. Rate CNP also allows for the recovery of the Company’s retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism is based on forward looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on invested capital. Retail rates increased due to environmental costs approximately 1.2% in January 2006, 0.6% in January 2007, and 2.4% in January 2008. On October 7, 2008, the Company agreed to defer collection during 2009 of any increase in rates under the portion of Rate CNP, which permits recovery of costs associated with environmental laws and regulations until 2010. The deferral of the retail rate adjustments will have an immaterial impact on annual cash flows, and will have no significant effect on the Company’s revenues or net income. On December 1, 2008, the Company made its submission of projected data for calendar year 2009. Fuel Cost Recovery The Company has established fuel cost recovery rates under an energy cost recovery clause (Rate ECR) approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. The Company, along with the Alabama PSC, will continue to monitor the under recovered fuel cost balance to determine whether an additional adjustment to billing rates is required. In June 2007, the Alabama PSC ordered the Company to increase its Rate ECR factor to 3.100 cents per kilowatt-hour (KWH) effective with billings beginning July 2007 for the 30-month period ending December 2009. The previous rate of 2.400 cents per KWH had been in effect since January 2006. This increase was intended to permit recovery of energy costs based on an estimate of future energy cost, as well as the collection of the existing under recovered energy cost by the end of 2009. During the recovery period, the Company was allowed to include a carrying charge associated with the under recovered fuel costs in the fuel expense calculation. In the event the application of this increased Rate ECR factor results in an over recovered position during this period, the Company would pay interest on any such over recovered balance at the same rate used to derive the carrying cost. On October 7, 2008, the Alabama PSC approved an increase in the Company’s Rate ECR factor to 3.983 cents per KWH for a 24- month period beginning with October 9, 2008 billings. Thereafter, the Rate ECR factor is 5.910 cents per KWH, absent a contrary order by the Alabama PSC. The previous rate of 3.100 cents per KWH had been in effect since July 2007. 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. During the 24-month period, the Company will be allowed to continue to include a carrying charge associated with the under recovered fuel costs in the fuel expense calculation. In the event the application of this increased Rate ECR factor results in an over recovered position during this period, the Company will pay interest on any such over recovered balance at the same rate used to derive the carrying cost. The Company’s under recovered fuel costs as of December 31, 2008 totaled $305.8 million as compared to $279.8 million at December 31, 2007. As a result of the Alabama PSC orders, the Company classified $180.9 million and $81.7 million of the under recovered regulatory clause revenues as deferred charges and other assets in the balance sheets as of December 31, 2008 and December 31, 2007, respectively. This classification is based on an estimate which includes such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of the recovery of the under recovered fuel costs. 49 NOTES (continued) Alabama Power Company 2008 Annual Report Natural Disaster Cost Recovery Based on an order by the Alabama PSC, the Company maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. In December 2005, the Alabama PSC approved a request by the Company to replenish the depleted NDR due to the hurricanes in 2005 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 which began in 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 three years. The second component of the NDR charge is intended to allow recovery of the existing deferred hurricane related operations and maintenance costs and any future reserve deficits over a 24-month period. Absent further Alabama PSC approval, 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. At December 31, 2008, the Company had an accumulated balance of $33.2 million in the target reserve for future storms, which is included in the balance sheets under “Other Regulatory Liabilities.” In June 2007, the Company fully recovered its storm cost of $51.3 million resulting from previous hurricanes. As a result, customer rates decreased by this portion of the NDR charge effective in July 2007. As revenue from the NDR charge is recognized, an equal amount of operations 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 annual cash flow. Nuclear Fuel Disposal Costs The Company has a contract with the United States, acting through 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. In July 2007, the U.S. Court of Federal Claims awarded the Company approximately $17 million, representing substantially all of the direct costs of the expansion of spent nuclear fuel storage facilities at Plant Farley from 1998 through 2004. In July 2007, the government filed a motion for reconsideration, which was denied in November 2007. On January 2, 2008, the government filed an appeal, and on February 29, 2008, filed a motion to stay the appeal. On April 1, 2008, the court granted the government’s motion to stay the appeal pending the court’s decisions in three other similar cases already on appeal. Those cases were decided in August 2008. Based on the rulings in those cases, the appeal is expected to proceed in first quarter 2009. On April 3, 2008, a second claim against the government was filed for damages incurred after December 31, 2004 (the court- mandated cut-off in the original claim), due to the government’s alleged continuing breach of contract. On October 31, 2008, the court denied a similar request by the government to stay this proceeding. The complaint does not contain any specific dollar amount for recovery of damages. Damages will continue to accumulate until the issue is resolved or the storage is provided. No amounts have been recognized in the financial statements as of December 31, 2008 for either claim. The final outcome of these matters cannot be determined at this time, but no material impact on net income is expected as any damage amounts collected from the government are expected to be returned to customers. An on-site dry spent fuel storage facility at Plant Farley is operational and can be expanded to accommodate spent fuel through the expected life of the plant. 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 years’ notice. The 50 NOTES (continued) Alabama Power Company 2008 Annual Report Company’s share of purchased power totaled $124 million in 2008, $105 million in 2007, and $95 million in 2006, 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, 2008, the capitalization of SEGCO consisted of $68 million of equity and $74 million of long-term debt on which the annual interest requirement is $3.2 million. SEGCO paid dividends totaling $7.8 million in 2008, $2.6 million in 2007, and $8.5 million in 2006, of which one-half of each was paid to the Company. In addition, the Company recognizes 50% 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, 2008 is as follows: Facility Total Megawatt Capacity Company Ownership Company Investment Accumulated Depreciation Greene County Plant Miller Units 1 and 2 (1) Jointly owned with an affiliate, Mississippi Power. (2) Jointly owned with PowerSouth. 1,320 500 (in millions) 60.00% (1) $130 91.84% (2) 986 $68 425 At December 31, 2008, the Company’s Plant Miller portion of construction work in progress was $174.4 million. 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 and the Company is responsible for providing its own financing. 5. INCOME TAXES Southern Company files a consolidated federal income tax return and combined income tax returns for the State of Georgia, State of Mississippi, 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 it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability. Current and Deferred Income Taxes Details of income tax provisions are as follows: Federal – Current Deferred State – Current Deferred Total 2008 2007 (in millions) $198 121 319 43 6 49 $368 $287 17 304 43 4 47 $351 2006 $302 (25) 277 56 (3) 53 $330 51 NOTES (continued) Alabama Power Company 2008 Annual Report 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: Deferred tax liabilities: Accelerated depreciation Property basis differences Premium on reacquired debt Pension and other benefits Fuel clause under recovered Regulatory assets associated with employee benefit obligations Asset retirement obligations Regulatory assets associated with asset retirement obligations Other Total Deferred tax assets: Federal effect of state deferred taxes State effect of federal deferred taxes Unbilled revenue Storm reserve Pension and other benefits Other comprehensive losses Regulatory liabilities associated with employee benefit obligations Asset retirement obligations Other Total Total deferred tax liabilities, net Portion included in current (liabilities) assets, net Accumulated deferred income taxes in the balance sheets 2008 2007 (in millions) $1,908 343 33 175 140 286 - 199 67 3,151 126 104 34 4 330 13 - 199 82 892 2,259 (16) $2,243 $1,766 341 36 340 128 90 27 187 60 2,975 121 96 31 3 126 10 178 214 88 867 2,108 (43) $2,065 At December 31, 2008, the Company’s tax-related regulatory assets and liabilities were $363 million and $90 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest. These liabilities are attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized investment tax credits. 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 $8.0 million in 2008, 2007, and 2006. At December 31, 2008, all investment tax credits available to reduce federal income taxes payable had been utilized. Effective Tax Rate A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: Federal statutory rate State income tax, net of federal deduction Non-deductible book depreciation Differences in prior years’ deferred and current tax rates AFUDC-equity Production activities deduction Other Effective income tax rate 2008 35.0% 3.1 0.9 (0.1) (1.6) (0.5) (0.8) 36.0% 2007 35.0% 3.2 0.9 (0.2) (1.3) (0.6) (0.7) 36.3% 2006 35.0% 4.0 1.0 (0.3) (0.7) (0.2) (0.9) 37.9% 52 NOTES (continued) Alabama Power Company 2008 Annual Report The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U. S. production activities as defined in Internal Revenue Code Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for years 2007 through 2009, and a 9% rate thereafter. The increase from 3% in 2006 to 6% in 2007 was one of several factors that increased the Company’s 2007 deduction by $7.8 million over the 2006 deduction. The resulting additional tax benefit was approximately $3 million. The IRS has not clearly defined a methodology for calculating this deduction. However, Southern Company has agreed with the IRS on a calculation methodology and signed a closing agreement on December 11, 2008. Therefore, the Company reversed the unrecognized tax benefit and adjusted the deduction for all previous years to conform to the agreement which resulted in a decrease in the 2008 deduction when compared to the 2007 deduction. The net impact of the reversal of the unrecognized tax benefits combined with the application of the new methodology had no material effect on the Company’s financial statements. Unrecognized Tax Benefits FIN 48 requires companies to determine whether it is “more likely than not” that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. It also provides guidance on the recognition, measurement, and classification of income tax uncertainties, along with any related interest and penalties. For 2008, the total amount of unrecognized tax benefits decreased by $1.8 million, resulting in a balance of $3.0 million as of December 31, 2008. Changes during the year in unrecognized tax benefits were as follows: Unrecognized tax benefits at beginning of year Tax positions from current periods Tax positions from prior periods Reductions due to settlements Reductions due to expired statute of limitations Balance at end of year 2008 (in millions) $4.8 0.8 (1.4) (1.2) - $3.0 2007 $1.2 1.5 2.1 - - $4.8 The reduction due to settlements relates to the agreement with the IRS regarding the production activities deduction methodology. See “Effective Tax Rate” above for additional information. Impact on the Company’s effective tax rate, if recognized, is as follows: Tax positions impacting the effective tax rate Tax positions not impacting the effective tax rate Balance of unrecognized tax benefits Accrued interest for unrecognized tax benefits: Interest accrued at beginning of year Interest reclassified due to settlements Interest accrued during the year Balance at end of year 2008 $3.0 - $3.0 2007 (in millions) $4.8 - $4.8 Change $(1.8) - $(1.8) 2008 (in millions) $0.4 (0.3) 0.2 $0.3 2007 $ - - 0.4 $0.4 The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax positions. It is reasonably possible that the amount of the unrecognized benefit with respect to a majority of the Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The possible conclusion or settlement of federal or state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. 53 NOTES (continued) Alabama Power Company 2008 Annual Report The IRS has audited and closed all tax returns prior to 2004. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2002. 6. FINANCING 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 $206 million, which constitute substantially all assets of these trusts and are reflected in the balance sheets as Long-term Debt Payable. 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, 2008, preferred securities of $200 million were outstanding. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities. Securities Due Within One Year At December 31, 2008, the Company had scheduled maturities and redemptions of senior notes due within one year totaling $250 million. At December 31, 2007, the Company had scheduled maturities and redemptions of senior notes, and preferred stock due within one year totaling $535 million. Maturities of senior notes through 2013 applicable to total long-term debt are as follows: $250 million in 2009; $100 million in 2010; $200 million in 2011; $500 million in 2012; and $250 million in 2013. Pollution Control Revenue Bonds Pollution control obligations represent loans to the Company from public authorities of funds or installment purchases of solid waste disposal 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. The Company incurred obligations related to the issuance of $254 million of pollution control revenue bonds in 2008. Proceeds from certain issuances are restricted until expenditures are incurred. During 2008, the Company was required to purchase a total of approximately $11 million of variable rate pollution control revenue bonds that were tendered by investors, all of which were subsequently remarketed. Also, during 2008, the Company entered into $330 million notional amount of interest rate swaps related to variable rate pollution control revenue bonds to hedge changes in interest rate for the period February 2008 through February 2010. The weighted average fixed payment rate on these hedges is 2.49% and the Company now has a total of $576 million of such hedges in place, with an overall weighted average fixed payment rate of 2.69%. Senior Notes The Company issued a total of $850 million of unsecured senior notes in 2008. The proceeds of these issuances were used to repay short-term indebtedness and for other general corporate purposes. At December 31, 2008 and 2007, the Company had $4.6 billion and $4.1 billion, respectively, of senior notes outstanding. These senior notes are subordinate to all secured debt of the Company which amounted to approximately $153 million at December 31, 2008. Preference and Common Stock In 2008, the Company issued no new shares of preference stock. The Company issued 7.5 million new shares of common stock to Southern Company at $40.00 per share and realized proceeds of $300 million. The proceeds of these issuances were used for general corporate purposes. 54 NOTES (continued) Alabama Power Company 2008 Annual Report Outstanding Classes of Capital Stock The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized and outstanding. The Company’s preferred stock and Class A preferred stock, without preference between classes, rank senior to the Company’s preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. The Company’s preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. Certain series of the preferred stock, Class A preferred stock, and preference stock are subject to redemption at the option of the Company on or after a specified date (typically 5 or 10 years after the date of issuance). Dividend Restrictions The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. Assets Subject to Lien The Company has granted liens on certain property in connection with the issuance of certain series of pollution control revenue bonds with an outstanding principal amount of $153 million, as of December 31, 2008. Bank Credit Arrangements The Company maintains committed lines of credit in the amount of $1.3 billion (including $582 million of such lines which are dedicated to funding purchase obligations relating to variable rate pollution control revenue bonds), of which $466 million will expire at various times during 2009. $379 million of the credit facilities expiring in 2009 allow for the execution of one-year term loans. $765 million of credit facilities expire in 2012. Most 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 average less than one-fourth of 1% for the Company. Compensating balances are not legally restricted from withdrawal. Most of the Company’s credit arrangements with banks have covenants that limit the Company’s debt to 65% 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, 2008, 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 uncommitted credit arrangements. As of December 31, 2008, the Company had $25 million of commercial paper outstanding. As of December 31, 2007, the Company had no commercial paper outstanding. During 2008 and 2007, the peak amount outstanding for short-term borrowings was $301 million and $214 million, respectively. The average amount outstanding in 2008 and 2007 was $40 million and $36 million, respectively. The average annual interest rate on short-term borrowings in 2008 was 2.31% and in 2007 was 5.34%. Short-term borrowings are included in notes payable in the balance sheets. At December 31, 2008, the Company had regulatory approval to have outstanding up to $2.0 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 manages a fuel-hedging program implemented per the guidelines of the Alabama PSC. The Company also enters into hedges of forward electricity sales. 55 NOTES (continued) Alabama Power Company 2008 Annual Report At December 31, 2008, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as assets/(liabilities) as follows: Regulatory hedges Cash flow hedges Non-accounting hedges Total fair value 2008 (in millions) $(91.9) - - $(91.9) 2007 $(0.7) 0.5 (0.2) $(0.4) Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company’s fuel hedging program, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expenses as they are recovered through the fuel cost recovery clauses. Gains and losses on energy-related derivatives designated as cash flow hedges are initially deferred in other comprehensive income before being recognized in income in the same period as the hedged transactions. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. There was no material ineffectiveness recorded in earnings for any period presented. The Company has energy-related hedges in place up to and including 2012. The Company also enters into derivatives to hedge exposure to changes in interest rates. Derivatives related to variable rate securities or forecasted transactions are accounted for as cash flow hedges. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. As such, no material ineffectiveness has been recorded in earnings for any period presented. At December 31, 2008, the Company had $576 million notional amount of interest rate derivatives outstanding that related to variable rate tax exempt debt, with net fair value losses of approximately $11 million as follows: Notional Amount Variable Rate Received Weighted Average Fixed Rate Paid Hedge Maturity Date Fair Value Gain (Loss) December 31, 2008 (in millions) $576 million $(11) * Hedged using the Securities Industry and Financial Markets Association Municipal Swap Index (SIFMA), February 2010 2.69%* SIFMA Index (formerly the Bond Market Association/PSA Municipal Swap Index) The fair value gain or loss for cash flow hedges are recorded in other comprehensive income and are reclassified into earnings at the same time the hedged items affect earnings. In 2007 and 2006, the Company settled gains/(losses) of $(6) million, and $18 million, respectively, upon termination of certain interest derivatives at the same time it issued debt and did not incur any such settlement gains/(losses) in 2008. The effective portions of 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 related underlying debt. For the years 2008, 2007, and 2006, approximately $(3) million, $(1) million, and $10 million, respectively, of pre-tax gains/(losses) were reclassified from other comprehensive income to interest expense. For 2009, pre-tax losses of approximately $8 million are expected to be reclassified from other comprehensive income to interest expense. The Company has interest-related hedges in place through 2010 and has deferred realized gains/(losses) that are being amortized through 2035. All derivative financial instruments are recognized as either assets or liabilities and are measured at fair value. See Note 10 for additional information. 7. COMMITMENTS Construction Program The Company is engaged in continuous construction programs, currently estimated to total $1.4 billion in 2009, $1.0 billion in 2010, and $1.0 billion in 2011. These amounts include $48 million, $37 million, and $45 million in 2009, 2010, and 2011, respectively, for construction expenditures related to contractual purchase commitments for nuclear fuel included under “Fuel Commitments.” The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates 56 NOTES (continued) Alabama Power Company 2008 Annual Report because of numerous factors. These factors include: changes in business conditions; revised load growth estimates; changes in environmental statutes and regulations; changes in nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; Alabama PSC approvals; 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. At December 31, 2008, 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 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, which are subject to price escalation, are made at various intervals based on actual operating hours of the respective units. Total remaining payments to GE under these agreements for facilities owned are currently estimated at $119 million over the remaining life of the agreements, which are currently estimated to range up to 8 years. 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. Limestone Commitments As part of the Company’s program to reduce sulfur dioxide emissions from its coal plants, the Company has begun construction of flue gas desulfurization projects and has entered into various long-term commitments for the procurement of limestone to be used in such equipment. Limestone contracts are structured with tonnage minimums and maximums in order to account for fluctuations in coal burn and sulfur content. The Company has a minimum contractual obligation of 3.0 million tons equating to approximately $124 million through 2019. Estimated expenditures (based on minimum contracted obligated dollars) over the next five years are $3 million in 2009, $10 million in 2010, $14 million in 2011, $14 million in 2012, and $15 million in 2013. 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. Coal commitments include forward contract purchases for sulfur dioxide and nitrogen oxide emission allowances. Natural gas purchase commitments contain fixed 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, 2008. Total estimated minimum long-term commitments at December 31, 2008 were as follows: 2009 2010 2011 2012 2013 2014 and thereafter Total commitments Natural Gas $ 505 266 120 154 157 210 $1,412 Commitments Coal (in millions) $1,461 996 808 636 474 1,414 $5,789 Nuclear Fuel $ 48 37 45 44 32 10 $216 Additional commitments for fuel will be required to supply the Company’s future needs. Total charges for nuclear fuel included in fuel expense totaled $70 million in 2008, $65 million in 2007, and $66 million in 2006. 57 NOTES (continued) Alabama Power Company 2008 Annual Report 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 traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. The creditworthiness of Southern Power is currently inferior to the creditworthiness of the traditional operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements. 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, 2008 were as follows: 2009 2010 2011 2012 2013 2014 and thereafter Total commitments Affiliated $61 17 - - - - $78 Commitments Non-Affiliated (in millions) $44 24 3 - - - $71 Total $105 41 3 - - - $149 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 $26.1 million in 2008, $27.7 million in 2007, and $30.3 million in 2006. Of these amounts, $19.2 million, $20.5 million, and $21.5 million for 2008, 2007, and 2006, respectively, relate to the rail car leases and are recoverable through the Company’s Rate ECR. At December 31, 2008, estimated minimum rental commitments for non-cancelable operating leases were as follows: 2009 2010 2011 2012 2013 2014 and thereafter Total Rail Cars $17 13 5 5 4 11 $55 Minimum Lease Payments Vehicles & Other (in millions) $6 6 4 2 1 - $19 Total $23 19 9 7 5 11 $74 Subsequent to December 31, 2008, the Company entered into rental agreements for coal rail cars resulting in the minimum lease commitments above increasing by $3 million in 2009, $4 million in 2010, $2 million in 2011, and $1 million each in years 2012 and 2013. 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 2010 and 2013, and the Company’s maximum obligations are $61.2 million and $18.6 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, 2008, the Company had outstanding guarantees related to SEGCO’s purchase of certain 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.” 58 NOTES (continued) Alabama Power Company 2008 Annual Report 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, 2008, there were 1,267 current and former employees of the Company participating in the stock option plan and there were 33.2 million shares of common stock remaining available for awards under this plan. 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. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. 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. For certain stock option awards, a change in control will provide accelerated vesting. The estimated fair values of stock options granted in 2008, 2007, and 2006 were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company’s stock over a period equal to the expected term. The Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted: Year Ended December 31 Expected volatility Expected term (in years) Interest rate Dividend yield Weighted average grant-date fair value 2008 13.1% 5.0 2.8% 4.5% $2.37 2007 14.8% 5.0 4.6% 4.3% $4.12 2006 16.9% 5.0 4.6% 4.4% $4.15 The Company’s activity in the stock option plan for 2008 is summarized below: Outstanding at December 31, 2007 Granted Exercised Cancelled Outstanding at December 31, 2008 Exercisable at December 31, 2008 Shares Subject to Option 6,186,430 1,148,493 (522,381) (3,346) 6,809,196 4,610,589 Weighted Average Exercise Price $30.50 35.78 27.68 32.31 $31.61 $29.65 The number of stock options vested and expected to vest in the future, as of December 31, 2008 was not significantly different from the number of stock options outstanding at December 31, 2008 as stated above. As of December 31, 2008, the weighted average remaining contractual term for the options outstanding and options exercisable was 6.1 years and 5.0 years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $36.7 million and $33.9 million, respectively. As of December 31, 2008, there was $1.1 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 10 months. For the years ended December 31, 2008, 2007 and 2006, total compensation cost for stock option awards recognized in income was $3.1 million, $4.9 million and $4.8 million, respectively, with the related tax benefit also recognized in income of $1.2 million, $1.9 million and $1.9 million, respectively. The compensation cost and tax benefits related to the grant and exercise of Southern Company stock options to the Company’s employees are recognized in the Company’s financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. 59 NOTES (continued) Alabama Power Company 2008 Annual Report The total intrinsic value of options exercised during the years ended December 31, 2008, 2007, and 2006 was $5.2 million, $9.7 million, and $4.9 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $2.0 million, $3.7 million, and $1.9 million, respectively, for the years ended December 31, 2008, 2007, and 2006. 9. NUCLEAR INSURANCE Under the Price-Anderson Amendments 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 $12.5 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 commercial nuclear reactors. The Company could be assessed up to $117.5 million per incident for each licensed reactor it operates but not more than an aggregate of $17.5 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 $235 million per incident but not more than an aggregate of $35 million to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than October 29, 2013. 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 $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL. NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member’s nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the 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 $39 million. Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12 month period is $3.2 billion plus such additional amounts NEIL, can recover through reinsurance, indemnity, or other sources. For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its bond trustees as may be appropriate under the policies and applicable trust indentures. All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes. 10. FAIR VALUE MEASUREMENTS On January 1, 2008, the Company adopted FASB Statement No. 157, “Fair Value Measurements” (SFAS No. 157) which defines fair value, establishes a framework for measuring fair value, and requires additional disclosures about fair value measurements. The criterion that is set forth in SFAS No. 157 is applicable to fair value measurement where it is permitted or required under other accounting pronouncements. SFAS No. 157 defines fair value as the exit price, which is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement. As a 60 NOTES (continued) Alabama Power Company 2008 Annual Report means to illustrate the inputs used, SFAS No. 157 establishes a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement. (cid:120) Level 1 consists of observable market data in an active market for identical assets or liabilities. (cid:120) Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. (cid:120) Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company’s own assumptions are the best available information. In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. The adoption of SFAS No. 157 has not resulted in any significant changes to the methodologies used for fair value measurement. Primarily all the changes in the fair value of assets and liabilities are recorded in other comprehensive income or regulatory assets and liabilities, and thus the impact on earnings is limited to derivatives that do not qualify for hedge accounting. The fair value measurements performed on a recurring basis and the level of the fair value hierarchy in which they fall at December 31, 2008 are as follows: At December 31, 2008: Level 1 Level 2 Level 3 Total Assets: Energy-related derivatives Nuclear decommissioning trusts(a) Cash equivalents and restricted cash Total fair value Liabilities: Energy-related derivatives Interest rate derivatives Total fair value (in millions) $ - 237.4 80.1 $ 317.5 $ 3.6 165.5 - $169.1 $ $ $ $ - - - $ 95.5 10.9 $106.4 $ $ - - - - - - - $ 3.6 402.9 80.1 $486.6 $ 95.5 10.9 $106.4 (a) Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Energy-related derivatives and interest rate derivatives primarily consist of over-the-counter contracts. See Note 6 under “Financial Instruments” for additional information. The nuclear decommissioning trust funds are invested in a diversified mix of equity and fixed income securities. See Note 1 under “Nuclear Decommissioning” for additional information. The cash equivalents and restricted cash consist of securities with original maturities of 90 days or less. All of these financial instruments and investments are valued primarily using the market approach. 11. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2008 and 2007 are as follows: Quarter Ended March 2008 June 2008 September 2008 December 2008 March 2007 June 2007 September 2007 December 2007 Operating Revenues $1,337 1,470 1,865 1,405 $1,197 1,336 1,635 1,192 The Company’s business is influenced by seasonal weather conditions. 61 Operating Income (in millions) Net Income After Dividends on Preferred and Preference Stock $274 319 478 198 $255 311 476 173 $130 153 252 81 $115 147 246 72 SELECTED FINANCIAL AND OPERATING DATA 2004-2008 Alabama Power Company 2008 Annual Report Operating Revenues (in thousands) Net Income after Dividends 2008 $6,076,931 2007 $5,359,993 2006 $5,014,728 2005 $4,647,824 2004 $4,235,991 on Preferred and Preference Stock (in thousands) $615,959 $579,582 $517,730 $507,895 $481,171 Cash Dividends on Common Stock (in thousands) Return on Average Common Equity (percent) Total Assets (in thousands) Gross Property Additions (in thousands) Capitalization (in thousands): Common stock equity Preferred and preference stock Long-term debt Total (excluding amounts due within one year) Capitalization Ratios (percent): Common stock equity Preferred and preference stock Long-term debt Total (excluding amounts due within one year) Security Ratings: First Mortgage Bonds - Moody's Standard and Poor's Fitch Preferred Stock/ Preference Stock - Moody's Standard and Poor's Fitch Unsecured Long-Term Debt - Moody's Standard and Poor's Fitch Customers (year-end): Residential Commercial Industrial Other Total Employees (year-end) $465,000 13.73 $491,300 13.30 $437,300 13.53 $16,536,006 $15,746,625 $14,655,290 $13,689,907 $12,781,525 $786,298 $1,532,673 $440,600 13.23 $409,900 13.72 $1,203,300 $890,062 $960,759 $4,854,310 685,127 5,604,791 $11,144,228 $4,410,683 683,512 4,750,196 $9,844,391 $4,032,287 612,407 4,148,185 $8,792,879 $3,792,726 465,046 3,869,465 $8,127,237 $3,610,204 465,047 4,164,536 $8,239,787 43.6 6.1 50.3 100.0 - - - Baa1 BBB+ A A2 A A+ 44.8 6.9 48.3 100.0 - - - Baa1 BBB+ A A2 A A+ 45.9 7.0 47.1 100.0 - - - Baa1 BBB+ A A2 A A+ 46.7 5.7 47.6 100.0 A1 A+ AA- Baa1 BBB+ A A2 A A+ 43.8 5.6 50.6 100.0 A1 A AA- Baa1 BBB+ A A2 A A+ 1,220,046 211,119 5,906 775 1,437,846 6,997 1,207,883 216,830 5,849 772 1,431,334 6,980 1,194,696 214,723 5,750 766 1,415,935 6,796 1,184,406 212,546 5,492 759 1,403,203 6,621 1,170,814 208,547 5,260 753 1,385,374 6,745 62 SELECTED FINANCIAL AND OPERATING DATA 2004-2008 (continued) Alabama Power Company 2008 Annual Report Operating Revenues (in thousands): Residential Commercial Industrial Other Total retail Wholesale - non-affiliates Wholesale - affiliates Total revenues from sales of electricity Other revenues Total Kilowatt-Hour Sales (in thousands): Residential Commercial Industrial Other Total retail Sales for resale - non-affiliates Sales for resale - affiliates Total Average Revenue Per Kilowatt-Hour (cents): Residential Commercial Industrial Total retail Wholesale Total sales Residential Average Annual Kilowatt-Hour Use Per Customer Residential Average Annual Revenue Per Customer Plant Nameplate Capacity Ratings (year-end) (megawatts) Maximum Peak-Hour Demand (megawatts): Winter Summer Annual Load Factor (percent) Plant Availability (percent): Fossil-steam Nuclear Source of Energy Supply (percent): Coal Nuclear Hydro Gas Purchased power - From non-affiliates From affiliates Total 2008 2007 2006 2005 2004 $1,997,603 1,459,466 1,381,100 24,112 4,862,281 711,903 308,482 5,882,666 194,265 $6,076,931 18,379,801 14,551,495 22,074,616 201,283 55,207,195 15,203,960 5,256,130 75,667,285 10.87 10.03 6.26 8.81 4.99 7.77 $1,833,563 1,313,642 1,238,368 21,383 4,406,956 627,047 144,089 5,178,092 181,901 $5,359,993 18,874,039 14,761,243 22,805,676 200,874 56,641,832 15,769,485 3,241,168 75,652,485 9.71 8.90 5.43 7.78 4.06 6.84 $1,664,304 1,172,436 1,140,225 18,766 3,995,731 634,552 216,028 4,846,311 168,417 $5,014,728 18,632,935 14,355,091 23,187,328 199,445 56,374,799 15,978,465 5,145,107 77,498,371 8.93 8.17 4.92 7.09 4.03 6.25 $1,476,211 1,062,341 1,065,124 17,745 3,621,421 551,408 288,956 4,461,785 186,039 $4,647,824 18,073,783 14,061,650 23,349,769 198,715 55,683,917 15,442,728 5,735,429 76,862,074 8.17 7.55 4.56 6.50 3.97 5.80 $1,346,669 980,771 948,528 16,860 3,292,828 483,839 308,312 4,084,979 151,012 $4,235,991 17,368,321 13,822,926 22,854,399 198,253 54,243,899 15,483,420 7,233,880 76,961,199 7.75 7.10 4.15 6.07 3.49 5.31 15,162 15,696 15,663 15,347 14,894 $1,648 $1,525 $1,399 $1,253 $1,155 12,222 12,222 12,222 12,216 12,216 10,144 12,211 59.4 88.2 87.5 60.9 16.5 1.8 8.7 1.8 10.3 100.0 10,309 11,744 61.8 89.6 93.3 60.2 17.4 3.8 7.6 2.1 8.9 100.0 9,812 11,162 63.2 90.5 92.9 59.5 17.2 5.6 6.8 3.8 7.1 100.0 9,556 10,938 63.2 87.8 88.7 56.5 16.4 5.6 8.9 5.4 7.2 100.0 10,747 11,518 60.9 90.08 94.13 58.5 17.8 2.9 9.2 2.9 8.7 100.0 63 DIRECTORS AND OFFICERS Alabama Power Company 2008 Annual Report Directors Whit Armstrong President, Chairman and CEO The Citizens Bank Ralph D. Cook 1 Attorney Hare, Wynn, Newell & Newton David J. Cooper, Sr. Vice Chairman Cooper/T. Smith Corporation John D. Johns Chairman, President and CEO Protective Life Corporation Patricia M. King President and CEO Sunny King Automotive Group James K. Lowder Chairman The Colonial Company Charles D. McCrary President and CEO Alabama Power Company Malcolm Portera Chancellor The University of Alabama System Robert D. Powers President The Eufaula Agency, Inc. David M. Ratcliffe Chairman, President and CEO Southern Company C. Dowd Ritter Chairman, President and CEO Regions Financial Corporation James H. Sanford Chairman HOME Place Farms, Inc. John C. Webb, IV President Webb Lumber Company, Inc. James W. Wright Chairman First Tuskegee Bank Officers Charles D. McCrary President and Chief Executive Officer Art P. Beattie Executive Vice President, Chief Financial Officer and Treasurer Mark A. Crosswhite Executive Vice President Steve R. Spencer Executive Vice President Gordon G. Martin Senior Vice President and General 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 Moses H. Feagin 2 Vice President and Comptroller William E. Zales, Jr. Vice President, Corporate Secretary and Assistant Treasurer Kathleen S. King 3 Vice President, Chief Information Officer Greg Barker Vice President Robert Bell 4 Vice President Matthew W. Bowden5 Vice President Willard L. Bowers Vice President Kenneth E. Coleman 6 Vice President, Southern Division J. Leigh Davis Vice President ` Larry R. Grill Vice President Gerald L. Johnson Vice President, Birmingham Division Marsha S. Johnson 7 Vice President William B. Johnson Vice President 64 Bobby J. Kerley Vice President Barbara J. Knight Vice President Myrna J. Pittman Vice President Leslie L. Sanders Vice President R. Michael Saxon Vice President, Southeast Division Julia H. Segars Vice President, Eastern Division Nicholas C. Sellers 8 Vice President Julian H. Smith, Jr. 9 Vice President Zeke W. Smith Vice President Cheryl A. Thompson Vice President, Mobile Division Terry H. Waters Vice President, Western Division Anita Allcorn-Walker Assistant Comptroller Ronald Q. Patterson Assistant Comptroller E. Wayne Boston Assistant Secretary and Assistant Treasurer Ceila H. Shorts Assistant Secretary Kay I. Worley Assistant Secretary J. Randy DeRieux Assistant Treasurer 1 Elected 7/08 2 Effective 5/08 3 Elected 10/08 4 Retired 4/08 5 Elected 1/09 6 Elected 4/08 7 Elected 4/08 8 Elected 4/08 9 Retired 6/08 CORPORATE INFORMATION Alabama Power Company 2008 Annual Report report General This annual 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. is submitted 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 the Southeast. The Company sells electricity to more than 1.4 million customers within its service area of approximately 45,000 square miles. In 2008, retail energy sales accounted for 73 percent of the Company’s total sales of 76 billion kilowatt-hours. to wholesale customers in The 5.30% Series Class A Preferred Stock The Bank of New York Mellon Shareowner Services 480 Washington Boulevard Jersey City, NJ 07310-1900 Number of Preferred and Preference Shareholders of record as of December 31, 2008 was 1,503. 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. The Company is a wholly owned subsidiary of The Southern Company, which is the parent company of four traditional operating companies and Southern Power Company. There is no established public trading market for the Company’s common stock. Alabama Power Company 600 North 18th Street Birmingham, AL 35203 (205) 257-1000 www.alabamapower.com Trustee, Registrar and Interest Paying Agent All series of Senior Notes and Trust Preferred Securities The Bank of New York Mellon Global Corporate Trust 505 North 20th Street, Suite 950 Birmingham, AL 35203 Registrar, Transfer Agent and Dividend Paying Agent All series except the 5.30% Series Class A Preferred Stock Southern Company Services, Inc. Stockholder Services P.O. Box 54250 Atlanta, GA 30308-0250 (800) 554-7626 Auditors Deloitte & Touche LLP 417 North 20th Street Suite 1000 Birmingham, AL 35203 Legal Counsel Balch & Bingham LLP P.O. Box 306 Birmingham, AL 35201 65 

Continue reading text version or see original annual report in PDF format above