Alabama Power Company
Annual Report 2014

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ALABAMA POWER COMPANY 2014 ANNUAL REPORT MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Alabama Power Company 2014 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 (2013) 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, 2014. Mark A. Crosswhite Chairman, President, and Chief Executive Officer Philip C. Raymond Executive Vice President, Chief Financial Officer, and Treasurer March 2, 2015 1 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors of 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 The Southern Company) as of December 31, 2014 and 2013, 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, 2014. 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 27 to 72) present fairly, in all material respects, the financial position of Alabama Power Company as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America. Birmingham, Alabama March 2, 2015 2 DEFINITIONS Term Meaning AFUDC ....................................... Allowance for funds used during construction ASC ............................................. Accounting Standards Codification CCR............................................. Coal combustion residuals Clean Air Act............................... Clean Air Act Amendments of 1990 CO2.............................................. Carbon dioxide DOE ............................................ U.S. Department of Energy EPA.............................................. U.S. Environmental Protection Agency FERC........................................... Federal Energy Regulatory Commission GAAP.......................................... Generally accepted accounting principles Georgia Power............................. Georgia Power Company Gulf Power .................................. Gulf Power Company IRS .............................................. Internal Revenue Service ITC .............................................. Investment tax credit KWH ........................................... Kilowatt-hour LIBOR......................................... London Interbank Offered Rate Mississippi Power ....................... Mississippi Power Company mmBtu......................................... Million British thermal units Moody's....................................... Moody's Investors Service, Inc. MW ............................................. Megawatt NDR ............................................ Natural Disaster Reserve NRC ............................................ U.S. Nuclear Regulatory Commission OCI.............................................. Other comprehensive income power pool................................... The operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power Company are subject to joint commitment and dispatch in order to serve their combined load obligations PPA.............................................. Power purchase agreement PSC.............................................. Public Service Commission Rate CNP..................................... Rate Certificated New Plant Rate CNP Environmental............ Rate Certificated New Plant Environmental Rate CNP PPA............................. Rate Certificated New Plant Power Purchase Agreement Rate ECR..................................... Rate energy cost recovery Rate NDR .................................... Natural disaster reserve rate Rate RSE ..................................... Rate stabilization and equalization plan ROE............................................. Return on equity S&P ............................................. Standard and Poor's Rating Services, a division of The McGraw Hill Companies, Inc. SCS.............................................. Southern Company Services, Inc. (the Southern Company system service company) SEC ............................................. U.S. Securities and Exchange Commission SEGCO........................................ Southern Electric Generating Company Southern Company system.......... The Southern Company, the traditional operating companies, Southern Power, SEGCO, Southern Nuclear, SCS, SouthernLINC Wireless, and other subsidiaries SouthernLINC Wireless .............. Southern Communications Services, Inc. Southern Nuclear......................... Southern Nuclear Operating Company, Inc. Southern Power ........................... Southern Power Company and its subsidiaries traditional operating companies .. Alabama Power Company, Georgia Power, Gulf Power, and Mississippi Power 3 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Alabama Power Company 2014 Annual Report OVERVIEW Business Activities Alabama Power Company (the Company) operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of the Company's business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future. Key Performance Indicators The Company continues to focus on several key performance indicators including 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 customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys to evaluate the Company's results and generally targets the top quartile of these surveys in measuring performance, which the Company achieved during 2014. 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 Company's fossil/hydro 2014 Peak Season EFOR of 2.5% was better than 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. The Company's performance for 2014 was better than the target for these transmission and distribution reliability measures. The Company uses net income after dividends on preferred and preference stock as the primary measure of the Company's financial performance. In 2014, the Company achieved its targeted net income after dividends on preferred and preference stock. See RESULTS OF OPERATIONS herein for additional information on the Company's financial performance. Earnings The Company's 2014 net income after dividends on preferred and preference stock was $761 million, representing a $49 million, or 6.9%, increase over the previous year. The increase was due primarily to an increase in weather-related revenues resulting from colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013, an increase in revenues related to net investments under Rate CNP Environmental, and an increase in AFUDC resulting from increased capital expenditures. The factors increasing net income were partially offset by an increase in total operating expenses. The Company's 2013 net income after dividends on preferred and preference stock of $712 million increased $8 million, or 1.1%, from the prior year. The increase in net income was due primarily to more favorable weather-related revenues in 2013 compared to 2012, an increase in AFUDC resulting from increased capital expenditures, and a decrease in interest expense resulting from lower interest rates. The factors increasing net income were partially offset by a decrease in revenues related to net investment under Rate CNP Environmental and a decrease in wholesale revenues to municipalities. 4 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report RESULTS OF OPERATIONS A condensed income statement for the Company follows: $ Operating revenues Fuel Purchased power Other operations and maintenance Depreciation and amortization Taxes other than income taxes Total operating expenses Operating income Allowance for equity funds used during construction Interest income Interest expense, net of amounts capitalized Other income (expense), net Income taxes Net income Dividends on preferred and preference stock Net income after dividends on preferred and preference stock $ Operating Revenues Amount 2014 Increase (Decrease) from Prior Year 2014 (in millions) 2013 5,942 1,605 385 1,468 603 356 4,417 1,525 49 15 (255) (22) 512 800 39 761 $ $ 324 (26) 156 179 (42) 8 275 49 17 (1) (4) 14 34 49 — 49 $ $ 98 128 (26) 2 6 8 118 (20) 13 — (28) (12) 1 8 — 8 Operating revenues for 2014 were $5.9 billion, reflecting a $324 million increase from 2013. Details of operating revenues were as follows: Retail — prior year Estimated change resulting from — 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 2014 2013 (in millions) $ 4,952 $ 4,933 81 7 85 124 5,249 281 189 470 223 (18) 4 21 12 4,952 248 212 460 206 $ 5,942 $ 5,618 5.8% 1.8% Retail revenues in 2014 were $5.2 billion. These revenues increased $297 million, or 6.0%, in 2014 and increased $19 million, or 0.4%, in 2013, each as compared to the prior year. The increase in 2014 was due to increased fuel revenues, colder weather in the 5 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013, and increased revenues related to net investments under Rate CNP Environmental primarily resulting from the inclusion of pre-2005 environmental assets. The increase in 2013 was due to more favorable weather, increased fuel revenues and increased revenues associated with Rate CNP PPA. The increase in 2013 was partially offset by a reduction in revenues related to net investments under Rate CNP Environmental. See Note 3 to the financial statements under "Retail Regulatory Matters" for additional information. See "Energy Sales" for a discussion of changes in the volume of energy sold, including changes related to sales growth and weather. 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 Note 3 to the financial statements under "Retail Regulatory Matters – Rate ECR" for additional information. Wholesale revenues from power sales to non-affiliated utilities were as follows: Capacity and other Energy Total non-affiliated 2014 $ $ 154 127 281 2013 (in millions) 143 $ 105 248 $ 2012 $ $ 160 117 277 Wholesale revenues from sales to non-affiliates will vary depending on the market prices of available wholesale energy compared to the cost of the Company's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. 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. In 2014, wholesale revenues from sales to non-affiliates increased $33 million, or 13.3%, as compared to the prior year primarily due to the availability of the Company's lower cost generation. This increase reflects a $22 million increase in revenues from energy sales and an $11 million increase in capacity revenues. In 2014, KWH sales increased 12.3% primarily due to the availability of the Company's lower cost generation and a 1.1% increase in the price of energy primarily due to higher natural gas prices. In 2013, wholesale revenues from sales to non-affiliates decreased $29 million, or 10.5%, as compared to the prior year due to a $17 million decrease in capacity revenues and a $12 million decrease in revenues from energy sales. In 2013, KWH sales decreased 11.3% primarily from decreased sales to municipalities, partially offset by a 0.8% increase in the price of energy. Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales and purchases are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through the Company's energy cost recovery clauses. In 2014, wholesale revenues from sales to affiliates decreased $23 million, or 10.8%, as compared to the prior year primarily related to a decrease in revenue from energy sales. In 2014, KWH sales decreased 21.7% primarily due to decreased hydro generation as the result of less rainfall as well as the addition of new generation in the Southern Company system, partially offset by a 13.7% increase in the price of energy primarily due to higher natural gas prices. In 2013, wholesale revenues from sales to affiliates increased $101 million, or 91.0%, as compared to the prior year primarily due to a $103 million increase in energy sales, partially offset by a $2 million decrease in capacity revenues. In 2013, KWH sales increased 88.9% and there was a 1.3% increase in the price of energy. In 2014, other operating revenues increased $17 million, or 8.3%, as compared to the prior year primarily due to increases in open access transmission tariff revenues, transmission service agreement revenues, and co-generation steam revenues. 6 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report Energy Sales Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2014 and the percent change from the prior year were as follows: Residential Commercial Industrial Other Total retail Wholesale — Non-affiliates Affiliates Total wholesale Total energy sales Total KWHs 2014 (in billions) 18.7 14.1 23.8 0.2 56.8 4.6 5.7 10.3 67.1 Total KWH Percent Change 2014 2013 Weather-Adjusted Percent Change 2014 2013 (0.8)% (1.3) 3.9 — 1.0 % (1.1)% 0.5 3.4 (1.4) 1.1 % 4.5% 1.6 3.9 — 3.5 12.3 (21.7) (9.4) 1.7% (0.5) 3.4 (1.4) 1.8 (10.8) 88.9 34.5 1.3% 6.3% Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales in 2014 were 3.5% higher than in 2013. Residential and commercial sales increased 4.5% and 1.6%, respectively, due primarily to colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013. Weather-adjusted residential and commercial sales decreased 0.8% and 1.3%, respectively, due primarily to a decrease in customer demand in 2014 compared to 2013. Industrial sales increased 3.9% in 2014 compared to 2013 as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, chemicals, automotive and plastics, and stone, clay, and glass sectors. Household income, one of the primary drivers of residential customer usage, was flat in 2014. Retail energy sales in 2013 were 1.8% higher than in 2012. Residential sales increased 1.7%, due primarily to more favorable weather in 2013. Weather-adjusted residential sales decreased 1.1% in 2013, primarily due to a decrease in customer demand. Commercial sales and weather-adjusted commercial sales remained relatively flat in 2013 compared to 2012. Industrial sales increased 3.4% in 2013 compared to 2012 as a result of an increase in demand resulting from changes in production levels primarily in the chemicals, primary metals, and stone, clay, and glass sectors. Weather adjusted wholesale non-affiliate KWH sales decreased 8.0% in 2014 and 11.0% in 2013 due primarily to a decrease in demand from municipalities. See "Operating Revenues" above for a discussion of significant changes in wholesale revenues from sales to non-affiliates and wholesale revenues from sales to affiliated companies as related to changes in price and KWH sales. 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. 7 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report Details of the Company's generation and purchased power were as follows: 2014 2013 2012 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)** * KWHs generated by hydro are excluded from the average cost of fuel, generated. 63.6 6.6 54 23 17 6 3.14 0.84 3.69 2.68 5.92 65.3 4.0 53 21 17 9 3.29 0.84 3.38 2.73 5.76 59.9 5.4 53 25 18 4 3.30 0.80 3.06 2.61 4.86 ** Average cost of purchased power includes fuel purchased by the Company for tolling agreements where power is generated by the provider. Fuel and purchased power expenses were $2.0 billion in 2014, an increase of $130 million, or 7.0%, compared to 2013. The increase was primarily due to a $147 million increase related to the volume of KWHs purchased and a $10 million increase in the average cost of purchased power. These increases were partially offset by a $19 million decrease in the average cost of fuel and an $8 million decrease in the volume of KWHs generated. Fuel and purchased power expenses were $1.9 billion in 2013, an increase of $102 million, or 5.8%, compared to 2012. The increase was primarily due to a $95 million increase in the volume of KWHs generated, a $38 million increase in the average cost of fuel, and a $37 million increase in the average cost of purchased power. These increases were partially offset by a $68 million decrease related to the volume of KWHs purchased. Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are generally offset by energy revenues through the Company's energy cost recovery clause. The Company, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate ECR" for additional information. Fuel Fuel expenses were $1.6 billion in 2014, a decrease of $26 million, or 1.6%, compared to 2013. The decrease was primarily due to a 4.5% decrease in the average cost of KWHs generated by coal, partially offset by a 30.8% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall, and a 9.2% increase in the average cost of KWHs generated by natural gas, which excludes tolling agreements. Fuel expenses were $1.6 billion in 2013, an increase of $128 million, or 8.5%, compared to 2012. This increase was primarily due to a 10.5% increase in the average cost of KWHs generated by natural gas, which excludes tolling agreements, and a 9.9% increase in KWHs generated by coal. This was partially offset by a 110.9% increase in the volume of KWHs generated by hydro facilities resulting from greater rainfall. Purchased Power – Non-Affiliates In 2014, purchased power expense from non-affiliates was $185 million, an increase of $85 million, or 85.0%, compared to 2013. The increase was primarily due to a 42.1% increase in the average cost per KWH purchased primarily due to demand during peak periods and a 28.8% increase in the amount of energy purchased to meet the demand created during cold weather in the first quarter 2014 and the addition of a new PPA in 2014. In 2013, purchased power expense from non-affiliates was $100 million, an increase of $27 million, or 37.0%, compared to 2012. The increase over the prior year was primarily due to a 52.6% increase in the amount of energy purchased, partially offset by a 17.2% decrease in the average cost per KWH. 8 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Purchased Power – Affiliates Purchased power expense from affiliates was $200 million in 2014, an increase of $71 million, or 55.0%, compared to 2013. This increase was primarily due to a 96.4% increase in the amount of energy purchased to meet the demand created during cold weather in the first quarter 2014, partially offset by a 20.8% decrease in the average cost per KWH purchased due to the availability of lower cost Southern Company system generation at the time of purchase. Purchased power expense from affiliates was $129 million in 2013, a decrease of $53 million, or 29.1%, compared to 2012. This decrease was primarily due to a 50.4% decrease in the amount of energy purchased, partially offset by a 42.5% increase in the average cost per KWH. Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC. Other Operations and Maintenance Expenses In 2014, other operations and maintenance expenses increased $179 million, or 13.9%, as compared to the prior year. Steam production, other power generation, and hydro generation expenses increased $110 million primarily due to scheduled outage costs. See Note 3 to the financial statements under "Retail Regulatory Matters – Cost of Removal Accounting Order" for additional information. Distribution and transmission expenses increased $31 million primarily related to increases in maintenance and labor expenses. Nuclear production expenses increased $14 million primarily related to labor expenses. Depreciation and Amortization Depreciation and amortization decreased $42 million, or 6.5%, in 2014 as compared to the prior year. The decrease in 2014 was primarily due to the amortization of $120 million of the regulatory liability for other cost of removal obligations, partially offset by increases due to depreciation rates related to environmental assets and amortization of certain regulatory assets. See Note 3 to the financial statements under "Retail Regulatory Matters – Cost of Removal Accounting Order" for additional information. In 2013, depreciation and amortization increased $6 million, or 0.9%, as compared to the prior year. The increase in 2013 was primarily due to an increase in depreciation related to environmental assets, additions to property, plant, and equipment related to distribution and transmission projects, as well as the amortization of software. These increases were partially offset by the deferral of certain expenses under an accounting order. See Note 3 to the financial statements under "Retail Regulatory Matters – Compliance and Pension Cost Accounting Order" for additional information. The increase related to environmental assets was offset by revenues under Rate CNP Environmental. Allowance for Equity Funds Used During Construction AFUDC equity increased $17 million, or 53.1%, in 2014 as compared to the prior year primarily due to an increase in capital expenditures related to environmental and steam generation. AFUDC equity increased $13 million, or 68.4%, in 2013 as compared to the prior year primarily due to increased capital expenditures associated with environmental, steam and nuclear generating facilities, and transmission. See Note 1 to financial statements under "Allowance for Funds Used During Construction" for additional information. Interest Expense, Net of Amounts Capitalized Interest expense, net of amounts capitalized decreased $28 million, or 9.8%, in 2013. The decrease in 2013 was primarily due to a decrease in interest rates and the timing of issuances and redemptions of long-term debt. Other Income (Expense), Net Other income (expense), net increased $14 million, or 38.9%, in 2014 as compared to the prior year primarily due to a decrease in non-operating expenses and an increase in sales of non-utility property. Other income (expense), net decreased $12 million, or 50.0%, in 2013 as compared to the prior year primarily due to increases in donations, partially offset by increases in non- operating income related to gains on sales of non-utility property. Income Taxes Income taxes increased $34 million, or 7.1%, in 2014 as compared to the prior year primarily due to higher pre-tax earnings. 9 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report Effects of Inflation The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company's results of operations has not been substantial in recent years. See Note 3 to the 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" and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information about regulatory matters. 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 timely recovery of prudently-incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining and growing sales which are subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the Company's service territory. Changes in regional and global economic conditions may impact sales for the Company, as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. Environmental Matters Compliance costs related to federal and state 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 differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See Note 3 to the financial statements under "Environmental Matters" for additional information. New Source Review Actions As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against the Company alleging violations of the New Source Review provisions of the Clean Air Act at certain coal-fired electric generating units, including a unit co-owned by Mississippi Power. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. See Note 3 to the financial statements under "Environmental Matters – New Source Review Actions" for additional information. The ultimate outcome of these matters cannot be determined at this time. Environmental Statutes and Regulations General The Company's operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; 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 2014, the Company had invested approximately $3.6 billion in environmental capital retrofit projects to comply with these requirements, with annual totals of approximately $355 million, $184 million, and $62 million for 2014, 2013, and 2012, respectively. The Company expects that capital expenditures to comply with existing environmental statutes and 10 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report regulations will total approximately $641 million from 2015 through 2017, with annual totals of approximately $417 million, $171 million, and $53 million for 2015, 2016, and 2017, respectively. Costs related to the proposed water and final CCR rules are not included in the estimated environmental capital expenditures. See "Capital Requirements and Contractual Obligations" for additional information regarding estimated incremental environmental compliance expenditures. In addition, these estimated expenditures do not include any potential compliance costs that may arise from the EPA's proposed rules that would limit CO2 emissions from new, existing, and modified or reconstructed fossil-fuel-fired electric generating units. See "Global Climate Issues" for additional information. The Company's ultimate environmental compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations and regulations relating to global climate change that are promulgated, including the proposed environmental regulations described below; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and the Company's fuel mix. Compliance costs may arise from existing unit retirements, installation of additional environmental controls, upgrades to the transmission system, closure and monitoring of CCR facilities, and adding or changing fuel sources for certain existing units. The ultimate outcome of these matters cannot be determined at this time. See "Retail Regulatory Matters –Environmental Accounting Order" herein for additional information on planned unit retirements and fuel conversions at the Company. Southern Electric Generating Company (SEGCO) is jointly owned with Georgia Power. As part of its environmental compliance strategy, SEGCO expects to complete the addition of natural gas as the primary fuel source for its generating units in 2015. The capacity of SEGCO's units is sold equally to the Company and Georgia Power through a PPA. If such compliance costs cannot continue to be recovered through retail rates, they could have a material financial impact on the Company's financial condition and results of operations. See Note 4 to the financial statements for additional information. Compliance with any new federal or state legislation or regulations relating to air quality, water, CCR, global climate change, or other environmental and health concerns could 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. Additionally, many of the Company's commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. Air Quality Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Since 1990, the Company has spent approximately $3.4 billion in reducing and monitoring emissions pursuant to the Clean Air Act. Additional controls are currently planned or under consideration to further reduce air emissions, maintain compliance with existing regulations, and meet new requirements. In 2012, the EPA finalized the Mercury and Air Toxics Standards (MATS) rule, which imposes stringent emissions limits for acid gases, mercury, and particulate matter on coal- and oil-fired electric utility steam generating units. Compliance for existing sources is required by April 16, 2015 up to April 16, 2016 for affected units for which extensions have been granted. On November 25, 2014, the U.S. Supreme Court granted a petition for review of the final MATS rule. The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozone National Ambient Air Quality Standard (NAAQS). In 2008, the EPA adopted a more stringent eight-hour ozone NAAQS, which it began to implement in 2011. In 2012, the EPA published its final determination of nonattainment areas based on the 2008 eight-hour ozone NAAQS. All areas within the Company's service territory have achieved attainment of this standard. On December 17, 2014, the EPA published a proposed rule to further reduce the current eight-hour ozone standard. The EPA is required by federal court order to complete this rulemaking by October 1, 2015. Finalization of a lower eight-hour ozone standard could result in the designation of new ozone nonattainment areas within the Company's service territory. The EPA regulates fine particulate matter concentrations on an annual and 24-hour average basis. All areas within the Company's service territory have achieved attainment with the 1997 and 2006 particulate matter NAAQS, and the EPA has officially redesignated former nonattainment areas within the service territory as attainment for these standards. In 2012, the EPA issued a final rule that increases the stringency of the annual fine particulate matter standard. The EPA promulgated final designations for the 2012 annual standard on December 18, 2014, and no new nonattainment areas were designated within the Company's service territory. The EPA has, however, deferred its designation decision for one area in Alabama, so future nonattainment designation of this area is possible. Final revisions to the NAAQS for sulfur dioxide (SO2), which established a new one-hour standard, became effective in 2010. No areas within the Company's service territory have been designated as nonattainment under this rule. However, the EPA has 11 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report announced plans to make additional designation decisions for SO2 in the future, which could result in nonattainment designations for areas within the Company's service territory. Implementation of the revised SO2 standard could require additional reductions in SO2 emissions and increased compliance and operational costs. On February 13, 2014, the EPA proposed to delete from the Alabama State Implementation Plan (SIP) the Alabama opacity rule that the EPA approved in 2008, which provides operational flexibility to affected units. In March 2013, the U.S. Court of Appeals for the Eleventh Circuit ruled in favor of the Company and vacated an earlier attempt by the EPA to rescind its 2008 approval. The EPA's latest proposal characterizes the proposed deletion as an error correction within the meaning of the Clean Air Act. The Company believes this interpretation of the Clean Air Act to be incorrect. If finalized, this proposed action could affect unit availability and result in increased operations and maintenance costs for affected units, including units co-owned with Mississippi Power and units owned by SEGCO, which is jointly owned with Georgia Power. The Company's service territory is subject to the requirements of the Cross State Air Pollution Rule (CSAPR). CSAPR is an emissions trading program that limits SO2 and nitrogen oxide emissions from power plants in 28 states in two phases, with Phase I beginning in 2015 and Phase II beginning in 2017. In 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated CSAPR in its entirety, but on April 29, 2014, the U.S. Supreme Court overturned that decision and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. The U.S. Court of Appeals for the District of Columbia Circuit granted the EPA's motion to lift the stay of the rule, and the first phase of CSAPR took effect on January 1, 2015. The EPA finalized the Clean Air Visibility Rule (CAVR) in 2005, with a goal of restoring natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of best available retrofit technology to certain sources, including fossil fuel-fired generating facilities, built between 1962 and 1977 and any additional emissions reductions necessary for each designated area to achieve reasonable progress toward the natural visibility conditions goal by 2018 and for each 10-year period thereafter. In 2012, the EPA published proposed revisions to the New Source Performance Standard (NSPS) for Stationary Combustion Turbines (CTs). If finalized as proposed, the revisions would apply the NSPS to all new, reconstructed, and modified CTs (including CTs at combined cycle units), during all periods of operation, including startup and shutdown, and alter the criteria for determining when an existing CT has been reconstructed. In February 2013, the EPA proposed a rule that would require certain states to revise the provisions of their SIPs relating to the regulation of excess emissions at industrial facilities, including fossil fuel-fired generating facilities, during periods of startup, shut-down, or malfunction (SSM). The EPA proposed to supplement the 2013 proposed rule on September 17, 2014, making it more stringent. The EPA has entered into a settlement agreement requiring it to finalize the proposed rule by May 22, 2015. The proposed rule would require states subject to the rule (including Alabama) to revise their SSM provisions within 18 months after issuance of the final rule. The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the current and proposed environmental requirements discussed above. As part of this strategy, the Company has developed a compliance plan for the MATS rule which includes reliance on existing emission control technologies, the construction of baghouses to provide an additional level of control on the emissions of mercury and particulates from certain generating units, the use of additives or other injection technology, the use of existing or additional natural gas capability, and unit retirements. Additionally, certain transmission system upgrades are required. The impacts of the eight-hour ozone, fine particulate matter and SO2 NAAQS, the Alabama opacity rule, CSAPR, CAVR, the MATS rule, the NSPS for CTs, and the SSM rule on the Company cannot be determined at this time and will depend on the specific provisions of the proposed and final rules, the resolution of pending and future legal challenges, and/or the development and implementation of rules at the state level. These regulations 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. Water Quality The EPA's final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities became effective on October 14, 2014. The effect of this final rule will depend on the results of additional studies and implementation of the rule by regulators based on site-specific factors. The ultimate impact of this rule will also depend on the outcome of ongoing legal challenges and cannot be determined at this time. In June 2013, the EPA published a proposed rule which requested comments on a range of potential regulatory options for addressing revised technology-based limits for certain wastestreams from steam electric power plants and best management practices for CCR surface impoundments. The EPA has entered into a consent decree requiring it to finalize revisions to the steam 12 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report electric effluent guidelines by September 30, 2015. The ultimate impact of the rule will also depend on the specific technology requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time. On April 21, 2014, the EPA and the U.S. Army Corps of Engineers jointly published a proposed rule to revise the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs, which would significantly expand the scope of federal jurisdiction under the CWA. In addition, the rule as proposed could have significant impacts on economic development projects which could affect customer demand growth. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time. If finalized as proposed, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. These proposed and final water quality regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. Coal Combustion Residuals The Company currently manages CCR at onsite storage units consisting of landfills and surface impoundments (CCR Units) at six generating plants. In addition to on-site storage, the Company also sells a portion of its CCR to third parties for beneficial reuse. Individual states regulate CCR and the State of Alabama has its own regulatory requirements. The Company has an inspection program in place to assist in maintaining the integrity of its coal ash surface impoundments. On December 19, 2014, the EPA issued the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), but has not yet published it in the Federal Register. The CCR Rule will regulate the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in CCR Units at active generating power plants. The CCR Rule does not mandate closure of CCR Units, but includes minimum criteria for active and inactive surface impoundments containing CCR and liquids, lateral expansions of existing units, and active landfills. Failure to meet the minimum criteria can result in the mandated closure of a CCR Unit. Although the EPA does not require individual states to adopt the final criteria, states have the option to incorporate the federal criteria into their state solid waste management plans in order to regulate CCR in a manner consistent with federal standards. The EPA's final rule continues to exclude the beneficial use of CCR from regulation. The ultimate impact of the CCR Rule cannot be determined at this time and will depend on the Company's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. The cost and timing of potential ash pond closure and ongoing monitoring activities that may be required in connection with the CCR Rule is also uncertain; however, the Company has developed a preliminary nominal dollar estimate of costs associated with closure and groundwater monitoring of ash ponds in place of approximately $311 million and ongoing post-closure care of approximately $49 million. The Company will record asset retirement obligations (ARO) for the estimated closure costs required under the CCR Rule during 2015. SEGCO, which is jointly owned with Georgia Power, will also record an ARO for ash ponds commonly used at Plant E.C. Gaston. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. Global Climate Issues In 2014, the EPA published three sets of proposed standards that would limit CO2 emissions from new, existing, and modified or reconstructed fossil-fuel-fired electric generating units. On January 8, 2014, the EPA published proposed standards for new units, and, on June 18, 2014, the EPA published proposed standards governing existing units, known as the Clean Power Plan, and separate standards governing CO2 emissions from modified and reconstructed units. The EPA's proposed Clean Power Plan establishes guidelines for states to develop plans to address CO2 emissions from existing fossil fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and final CO2 emission rate goals to be achieved between 2020 and 2029 and in 2030 and thereafter. The proposed guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through market based contracts. The Southern Company system filed comments on the EPA's proposed Clean Power Plan on December 1, 2014. These comments addressed legal and technical issues in addition to providing a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA's compliance scenarios. Costs associated with this proposal could be significant to the utility industry and the Southern Company system. However, the ultimate financial and operational impact of the proposed Clean Power Plan on the Southern Company system cannot be determined at this time and will depend upon numerous known and unknown factors. Some of the unknown factors include: the structure, timing, and content of the EPA's final guidelines; individual state 13 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report implementation of these guidelines, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions- related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required. Over the past several years, the U.S. Congress has also considered many proposals to reduce greenhouse gas emissions, mandate renewable or clean energy, and impose energy efficiency standards. Such proposals are expected to continue to be considered by the U.S. Congress. International climate change negotiations under the United Nations Framework Convention on Climate Change are also continuing. The EPA's greenhouse gas reporting rule requires annual reporting of CO2 equivalent emissions in metric tons for a company's operational control of facilities. Based on ownership or financial control of facilities, the Company's 2013 greenhouse gas emissions were approximately 40.8 million metric tons of CO2 equivalent. The preliminary estimate of the Company's 2014 greenhouse gas emissions on the same basis is approximately 40 million metric tons of CO2 equivalent. The level of greenhouse gas emissions from year to year will depend on the level of generation, the mix of fuel sources, and other factors. Retail Regulatory Matters The Company's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. The Company currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting the Company. See Note 1 to the financial statements under "Nuclear Outage Accounting Order" and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information regarding the Company's rate mechanisms and accounting orders. Rate RSE 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 4.0% and any annual adjustment is limited to 5.0%. If the Company's actual retail return is above the allowed weighted cost of equity (WCE) range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range. On December 1, 2014, the Company submitted the required annual filing under Rate RSE to the Alabama PSC. The Rate RSE increase was 3.49%, or $181 million annually, effective January 1, 2015. The revenue adjustment includes the performance based adder of 0.07%. Under the terms of Rate RSE, the maximum increase for 2016 cannot exceed 4.51%. 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 under Rate CNP. The Company may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 4, 2014, the Alabama PSC issued a consent order that the Company leave in effect the current Rate CNP PPA factor for billings for the period April 1, 2014 through March 31, 2015. It is anticipated that no adjustment will be made to Rate CNP PPA in 2015. The Company has elected the normal purchase normal sale (NPNS) scope exception under the derivative accounting rules for its two wind PPAs, which total approximately 400 MWs. The NPNS exception allows the PPAs to be recorded at a cost, rather than fair value, basis. The industry's application of the NPNS exception to certain physical forward transactions in nodal markets was previously under review by the SEC at the request of the electric utility industry. In June 2014, the SEC requested the Financial Accounting Standards Board to address the issue through the Emerging Issues Task Force (EITF). Any accounting decisions will now be subject to EITF deliberations. The outcome of the EITF's deliberations cannot be determined at this time. If the Company is ultimately required to record these PPAs at fair value, an offsetting regulatory asset or regulatory liability will be recorded. Rate CNP Environmental allows for the recovery of the Company's retail costs associated with environmental laws, regulations, or other such mandates. Rate CNP Environmental 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 certain invested capital. The Rate CNP Environmental increase effective January 1, 2015 was 1.5%, or $75 million annually, based upon projected billings. Rate ECR The Company has established energy cost recovery rates under the Company's Rate ECR as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate 14 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. The Company, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on the Company's net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH. In December 2014, the Alabama PSC issued a consent order that the Company leave in effect for 2015 the energy cost recovery rates which began in 2011. Therefore, the Rate ECR factor as of January 1, 2015 remained at 2.681 cents per KWH. Effective with billings beginning in January 2016, the Rate ECR factor will be 5.910 cents per KWH, absent a further order from the Alabama PSC. Environmental Accounting Order Based on an order from the Alabama PSC, the Company is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. These costs would be amortized over the affected unit's remaining useful life, as established prior to the decision regarding early retirement. See "Environmental Matters – Environmental Statutes and Regulations" herein for additional information regarding environmental regulations. As part of its environmental compliance strategy, the Company plans to retire Plant Gorgas Units 6 and 7. These units represent 200 MWs of the Company's approximately 12,200 MWs of generating capacity. The Company also plans to cease using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. Additionally, the Company expects to cease using coal at Plant Barry Unit 3 (225 MWs) and Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. These plans are expected to be effective no later than April 2016. In accordance with an accounting order from the Alabama PSC, the Company will transfer the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized through Rate CNP Environmental over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on the Company's financial statements. Cost of Removal Accounting Order In accordance with an accounting order issued on November 3, 2014 by the Alabama PSC, at December 31, 2014, the Company fully amortized the balance of $123 million in certain regulatory asset accounts, and offset this amortization expense with the amortization of $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset account balances amortized as of December 31, 2014 represented costs previously deferred under a compliance and pension cost accounting order as well as a non-nuclear outage accounting order, which were approved by the Alabama PSC in 2012 and August 2013, respectively. Approximately $95 million of non-nuclear outage costs and $28 million of compliance and pension costs were fully amortized at December 31, 2014. The cost of removal accounting order also required the Company to terminate, as of December 31, 2014, the regulatory asset accounts created pursuant to the compliance and pension cost accounting order and the non-nuclear outage accounting order. Consequently, the Company will not defer any expenditures in 2015, 2016, and 2017 related to critical electric infrastructure and domestic nuclear facilities, as allowed under the previous orders. Non-Environmental Federal Mandated Costs Accounting Order On December 9, 2014, pending the development of a new cost recovery mechanism, the Alabama PSC issued an accounting order authorizing the deferral as a regulatory asset of up to $50 million of costs associated with non-environmental federal mandates that would otherwise impact rates in 2015. On February 17, 2015, the Company filed a proposed modification to Rate CNP Environmental with the Alabama PSC to include compliance costs for both environmental and non-environmental mandates. The non-environmental costs that would be recovered through the revised mechanism concern laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting the Company's facilities or operations. If approved as requested, the effective date for the revised mechanism would be March 20, 2015, upon which the regulatory asset balance would be reclassified to the under recovered balance for Rate CNP Environmental, and the related customer rates would not become effective before January 2016. The ultimate outcome of this matter cannot be determined at this time. 15 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report Income Tax Matters Bonus Depreciation On December 19, 2014, the Tax Increase Prevention Act of 2014 (TIPA) was signed into law. The TIPA retroactively extended several tax credits through 2014 and extended 50% bonus depreciation for property placed in service in 2014 (and for certain long-term production-period projects to be placed in service in 2015). The extension of 50% bonus depreciation had a positive impact on the Company's cash flows and, combined with bonus depreciation allowed in 2014 under the American Taxpayer Relief Act of 2012, resulted in approximately $165 million of positive cash flows for the 2014 tax year. The estimated cash flow benefit of bonus depreciation related to TIPA is expected to be approximately $65 million to $70 million for the 2015 tax year. Other Matters In accordance with accounting standards related to employers' accounting for pensions, the Company recorded pension costs of $23 million in 2014, $47 million in 2013 and $6 million in 2012. Postretirement benefit costs for the Company were $4 million, $7 million, and $10 million in 2014, 2013, and 2012, 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. The Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. 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 air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. 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 or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential. ACCOUNTING POLICIES Application of Critical Accounting Policies and Estimates The Company prepares its financial statements in accordance with GAAP. 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 the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors. Electric Utility Regulation The Company is subject to retail regulation by the Alabama PSC and wholesale regulation by the FERC. As a result, the Company applies accounting standards which require 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 the accounting standards 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, AROs, and pension and postretirement benefits have less of a direct impact on the Company's results of operations and financial condition than they would on a non-regulated company. As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on 16 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements. Contingent Obligations The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that subject it to environmental, litigation, 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 GAAP, records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable. 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 position, results of operations, or cash flows. Pension and Other Postretirement Benefits The Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations. Key elements in determining the Company's pension and other postretirement benefit expense in accordance with GAAP are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on postretirement benefit plan assets is based on the Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company's target asset allocation. The Company discounts the future cash flows related to its postretirement benefit plans using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. For purposes of its December 31, 2014 measurement date, the Company adopted new mortality tables for its pension plans and retiree life and medical plans, which reflect increased life expectancies in the U.S. The adoption of new mortality tables increased the projected benefit obligations for the Company's pension plans and other postretirement benefit plans by approximately $156 million and $22 million, respectively. The adoption of new mortality tables will increase net periodic costs related to the Company's pension plans and other postretirement benefit plans in 2015 by $20 million and $2 million, respectively. A 25 basis point change in any significant assumption (discount rate, salaries, or long-term return on plan assets) would result in an $8 million or less change in total annual benefit expense and a $113 million or less change in projected obligations. Recently Issued Accounting Standards On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. FINANCIAL CONDITION AND LIQUIDITY Overview The Company's financial condition remained stable at December 31, 2014. The Company's cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. Capital expenditures and other investing activities include investments to comply with environmental regulations and for restoration following major storms. Operating cash flows provide a substantial portion of the Company's cash needs. For the three-year period from 2015 through 2017, the Company's projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. Projected capital expenditures in that period include investments to maintain existing generation facilities, to add environmental equipment for existing generating units, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities. The Company plans to finance future cash needs in excess of its operating cash flows primarily through debt and equity issuances. The Company intends to continue to monitor its access to short- 17 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information. The Company's investments in the qualified pension plan and the nuclear decommissioning trust funds increased in value as of December 31, 2014 as compared to December 31, 2013. No contributions to the qualified pension plan were made for the year ended December 31, 2014. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2015. The Company's funding obligations for the nuclear decommissioning trust fund are based on the site study, and the next study is expected to be conducted in 2018. See Notes 1 and 2 to the financial statements under "Nuclear Decommissioning" and "Pension Plans," respectively, for additional information. Net cash provided from operating activities totaled $1.7 billion for 2014, a decrease of $205 million as compared to 2013. The decrease in cash provided from operating activities was primarily due to an increase in income tax payments and the timing of fossil fuel stock purchases, partially offset by the timing of payment of accounts payable. Net cash provided from operating activities totaled $1.9 billion for 2013, an increase of $538 million as compared to 2012. The increase in cash provided from operating activities was primarily due to changes in timing of fossil fuel stock purchases and payment of accounts payable, and collection of fuel cost recovery revenues. Net cash used for investing activities totaled $1.6 billion for 2014, $1.1 billion for 2013, and $0.9 billion for 2012. In 2014, these additions were primarily due to gross property additions related to environmental, distribution, transmission, steam generation, and nuclear fuel. In 2013, these additions were primarily due to gross property additions related to steam generation, distribution, and transmission equipment. In 2012, these additions were primarily due to gross property additions related to nuclear fuel and transmission, distribution, and steam generating equipment. Net cash used for financing activities totaled $164 million in 2014 primarily due to the payment of common stock dividends, and issuances and redemptions of securities. Net cash used for financing activities totaled $614 million in 2013 primarily due to the payment of common stock dividends, and the issuance and a maturity of senior notes. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities. Significant balance sheet changes for 2014 included an increase of $854 million in property, plant, and equipment primarily due to additions to environmental, distribution, transmission, and steam generation. Other significant changes included increases of $454 million in securities due within one year and $418 million in other regulatory assets, deferred related to pension and other postretirement benefits. The Company's ratio of common equity to total capitalization, including short-term debt, was 45.6% in 2014 and 44.3% in 2013. See Note 6 to the financial statements for additional information. 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. The Company has primarily utilized funds from operating cash flows, short-term debt, security issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing 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 SEC 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 in the Southern Company system. 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. 18 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report At December 31, 2014, the Company had approximately $273 million of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2014 were as follows: Expires(a) 2015 2016 2018 Total $ 228 $ 50 $ 1,030 $ 1,308 (a) No credit arrangements expire in 2017. Unused (in millions) 1,308 $ Executable Term-Loans One Year Two Years Due Within One Year No Term Out Term Out $ 58 $ — $ 58 $ 170 See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information. Most of these bank credit arrangements contain covenants that limit debt levels and contain cross default provisions to other indebtedness (including guarantee obligations) of the Company. Such cross default provisions to other indebtedness would trigger an event of default if the Company defaulted on indebtedness or guarantee obligations over a specified threshold. The Company is currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings. The Company expects to renew its bank credit arrangements as needed, prior to expiration. A portion of the unused credit with banks is allocated to provide liquidity support to the Company's variable rate pollution control revenue bonds and commercial paper borrowings. As of December 31, 2014, the Company had $784 million of outstanding variable rate pollution control revenue bonds requiring liquidity support. In addition, at December 31, 2014, the Company had $280 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. 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 may meet short-term cash needs through its commercial paper program. 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. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support. Details of short-term borrowings were as follows: Short-term Debt at the End of the Period Amount Outstanding (in millions) $— $— $— Weighted Average Interest Rate —% —% —% December 31, 2014: Commercial paper December 31, 2013: Commercial paper December 31, 2012: Commercial paper Short-term Debt During the Period (a) Weighted Average Interest Rate Maximum Amount Outstanding (in millions) Average Outstanding (in millions) $13 $11 $6 0.2% 0.2% 0.2% $300 $90 $57 (a) Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2014, 2013, and 2012. The Company believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash. Financing Activities In August 2014, the Company issued $400 million aggregate principal amount of Series 2014A 4.150% Senior Notes due August 15, 2044. The proceeds were used for general corporate purposes, including the Company's continuous construction program. During 2014, the Company entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $200 million. 19 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report In December 2014, the Company incurred obligations related to the issuance of $254 million of The Industrial Development Board of the Town of Columbia, Pollution Control Revenue Refunding Bonds (Alabama Power Company Project), Series 2014 – A, 2014 – B, 2014 – C, and 2014 – D due December 1, 2037. The proceeds were used to refund, in December 2014, approximately $254 million of The Industrial Development Board of the Town of Columbia, Pollution Control Revenue Refunding Bonds (Alabama Power Company Project), Series 1995 – A, 1995 – B, 1995 – C, 1995 – D, 1995 – E, 1996 – A, 1999 – A, 1999 – B, and 1999 – C. Subsequent to December 31, 2014, the Company announced the redemption of $250 million aggregate principal amount of its Series DD 5.65% Senior Notes due March 15, 2035, which will occur on March 16, 2015. 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 below BBB- and/or Baa3. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At December 31, 2014, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $365 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system 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 and the variable rate pollution control revenue bond market. Market Price Risk Due to cost-based rate regulation and other various cost recovery mechanisms, the Company continues to have 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. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. To mitigate future exposure to changes in interest rates, the Company enters into derivatives that have been designated as hedges. The weighted average interest rate on $984 million of long-term variable interest rate exposure at January 1, 2015 was 0.71%. If the Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would affect annualized interest expense by approximately $10 million at January 1, 2015. See Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements for additional information. To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and financial hedge contracts for natural gas purchases. The Company continues to manage a retail fuel-hedging program implemented per the guidelines of the Alabama PSC. The Company had no material change in market risk exposure for the year ended December 31, 2014 when compared to the year ended December 31, 2013. In addition, 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. 20 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, were as follows: 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 2014 Changes 2013 Changes Fair Value (in millions) $ $ (1) (7) (44) (52) $ $ (13) 10 2 (1) (a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any. The net hedge volumes of energy-related derivative contracts, for the years ended December 31 were as follows: Commodity – Natural gas swaps Commodity – Natural gas options Total hedge volume 2014 2013 mmBtu Volume (in millions) 54 2 56 64 5 69 The weighted average swap contract cost above market prices was approximately $0.89 per mmBtu as of December 31, 2014 and $0.02 per mmBtu as of December 31, 2013. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. The majority of the natural gas hedge gains and losses are recovered through the Company's retail energy cost recovery clause. At December 31, 2014 and 2013, substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and were related to the Company's fuel-hedging program. Therefore, 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 energy cost recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in OCI 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 and were not material for any year presented. The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note 10 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts, which are all Level 2 of the fair value hierarchy, at December 31, 2014 were as follows: Level 1 Level 2 Level 3 Fair value of contracts outstanding at end of period Total Fair Value $ $ — (52) — (52) Fair Value Measurements December 31, 2014 Maturity Year 1 (in millions) $ $ — (31) — (31) Years 2&3 $ $ — (21) — (21) The Company is exposed to market price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment 21 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report grade credit ratings by Moody's and S&P, 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 Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements. Capital Requirements and Contractual Obligations The Company's construction program consists of a base level capital investment and capital expenditures to comply with existing environmental statutes and regulations. Over the next three years, the Company estimates spending, as part of its base level capital investment, $515 million on Plant Farley (including nuclear fuel), $892 million on distribution facilities, and $556 million on transmission additions. These base level capital investment amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements. Costs related to proposed water and final CCR rules are not included in the construction program base level capital investment. In addition, these estimated expenditures do not include any potential compliance costs that may arise from the EPA's proposed rules that would limit CO2 emissions from new, existing, and modified or reconstructed fossil-fuel-fired electric generating units. See "Global Climate Issues" for additional information. The Company's base level construction program investments including investments to comply with existing environmental statutes and regulations and the estimated incremental compliance costs related to the proposed water and final CCR rules over the 2015 through 2017 three-year period, based on the final CCR rule which will continue to regulate CCR as non-hazardous solid waste, are estimated as follows: Construction program: Base capital Existing environmental statutes and regulations Total construction program base level capital investment Estimated incremental environmental compliance investments: Proposed water and final CCR rules 2015 $ $ $ 1,114 417 1,531 4 2016 (in millions) $ $ $ 857 171 1,028 88 2017 $ $ $ 1,092 53 1,145 239 See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" for additional information. The construction program is 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; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in the expected environmental compliance program; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; 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, 2014, in addition to the funds required for the Company's construction program, approximately $454 million will be required by the end of 2015 for maturities of long-term debt. Subsequent to December 31, 2014, the Company announced the redemption of $250 million aggregate principal amount of its Series DD 5.65% Senior Notes due March 15, 2035 that will occur on March 16, 2015, which increased the total funds required for maturities of long-term debt by the end of 2015 to $704 million. The Company plans to continue, when economically feasible, to retire higher cost securities and replace these obligations with lower cost capital if market conditions permit. As a result of NRC 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, as discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the Alabama PSC and the FERC. Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 2, 6, 7, and 11 to the financial statements for additional information. 22 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report Contractual Obligations Long-term debt(a) — Principal Interest Preferred and preference stock dividends(b) Financial derivative obligations(c) Operating leases(d) Capital Lease Purchase commitments — Capital(e) Fuel(f) Purchased power(g) Other(h) Pension and other postretirement benefit plans(i) Total 2015 2016- 2017 2018- 2019 (in millions) After 2019 Total $ 454 259 39 40 16 — 1,343 1,297 68 45 18 $ 761 503 79 21 24 1 2,281 1,705 144 81 33 $ 200 435 79 — 11 1 — 867 156 81 — $ 5,216 3,436 — — 17 3 — 529 854 365 — $ 6,631 4,633 197 61 68 5 3,624 4,398 1,222 572 51 $ 3,579 $ 5,633 $ 1,830 $ 10,420 $ 21,462 (a) All amounts are reflected based on final maturity dates. 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. Variable rate interest obligations are estimated based on rates as of January 1, 2015, 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) Includes derivative liabilities related to cash flow hedges of forecasted debt, as well as energy-related derivatives. For additional information, see Notes 1 and 11 to the financial statements. (d) Excludes PPAs that are accounted for as leases and are included in purchased power. (e) The Company provides estimated capital expenditures for a three-year period, including capital expenditures and compliance costs associated with existing environmental regulations. Such amounts exclude the Company's estimates of potential incremental environmental compliance investment to comply with proposed water and final CCR rules, which are approximately $4 million, $88 million, and $239 million for 2015, 2016, and 2017, respectively. These amounts also exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements, which are reflected separately. At December 31, 2014, significant purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" for additional information. (f) Includes commitments to purchase coal, nuclear fuel, and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2014. (g) Estimated minimum long-term obligations for various long-term commitments for the purchase of capacity and energy. Amounts are related to the Company's certificated PPAs which include MWs purchased from gas-fired and wind-powered facilities. (h) Includes long-term service agreements and contracts for the procurement of limestone. Long-term service agreements include price escalation based on inflation indices. (i) The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets. 23 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report Cautionary Statement Regarding Forward-Looking Statements The Company's 2014 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail rates, economic recovery, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, access to sources of capital, projections for the qualified pension plan, postretirement benefit plan, and nuclear decommissioning trust fund contributions, financing activities, filings with state and federal regulatory authorities, impact of the TIPA, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and 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 changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws including regulation of water, CCR, and emissions of sulfur, nitrogen, CO2, soot, particulate matter, hazardous air pollutants, including mercury, 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, pending EPA civil action against the Company, and IRS and state tax audits; 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 and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions; available sources and costs of fuels; effects of inflation; the ability to control costs and avoid cost overruns during the development and construction of facilities, to construct facilities in accordance with the requirements of permits and licenses, and to satisfy any operational and environmental performance standards; investment performance of the Company's employee and retiree benefit plans and nuclear decommissioning trust funds; 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 other cost recovery mechanisms; the inherent risks involved in operating nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, or financial risks; the ability to successfully operate generating, transmission, and distribution facilities and the successful performance of necessary corporate functions; 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 wholesale customers; the direct or indirect effect on the Company's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist incidents; interest rate fluctuations and financial market conditions and the results of financing efforts; changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements; the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on currency exchange rates, counterparty performance, and the economy in general; the ability of the Company to obtain additional generating capacity at competitive prices; 24 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2014 Annual Report • • • • catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences; the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources; 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. 25 (cid:62)(cid:55)(cid:75)(cid:76)(cid:86)(cid:3)(cid:83)(cid:68)(cid:74)(cid:72)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:81)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:79)(cid:92)(cid:3)(cid:79)(cid:72)(cid:73)(cid:87)(cid:3)(cid:69)(cid:79)(cid:68)(cid:81)(cid:78)(cid:64) 26 STATEMENTS OF INCOME For the Years Ended December 31, 2014, 2013, and 2012 Alabama Power Company 2014 Annual Report Operating Revenues: Retail revenues Wholesale revenues, non-affiliates Wholesale revenues, affiliates Other revenues Total operating revenues Operating Expenses: Fuel Purchased power, non-affiliates Purchased power, 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 2014 2013 (in millions) 2012 $ 5,249 $ 4,952 $ 4,933 281 189 223 5,942 1,605 185 200 1,468 603 356 4,417 1,525 49 15 (255) (22) (213) 1,312 512 800 39 248 212 206 5,618 1,631 100 129 1,289 645 348 4,142 1,476 32 16 (259) (36) (247) 1,229 478 751 39 277 111 199 5,520 1,503 73 182 1,287 639 340 4,024 1,496 19 16 (287) (24) (276) 1,220 477 743 39 704 Net Income After Dividends on Preferred and Preference Stock $ 761 $ 712 $ The accompanying notes are an integral part of these financial statements. 27 STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2014, 2013, and 2012 Alabama Power Company 2014 Annual Report Net Income Other comprehensive income (loss): Qualifying hedges: 2014 2013 (in millions) 2012 $ 800 $ 751 $ 743 Changes in fair value, net of tax of $(3), $-, and $(7), respectively Reclassification adjustment for amounts included in net income, net of tax of $1, $1, and $1, respectively Total other comprehensive income (loss) Comprehensive Income $ (5) 2 (3) 797 — 1 1 $ 752 $ (11) 2 (9) 734 The accompanying notes are an integral part of these financial statements. 28 STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2014, 2013, and 2012 Alabama Power Company 2014 Annual Report Operating Activities: Net income Adjustments to reconcile net income to net cash provided from operating activities — Depreciation and amortization, total Deferred income taxes Allowance for equity funds used during construction Pension, postretirement, and other employee benefits Stock based compensation expense 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 -Retail fuel cost over recovery -Other current liabilities Net cash provided from operating activities Investing Activities: Property additions Nuclear decommissioning trust fund purchases Nuclear decommissioning trust fund sales Cost of removal net of salvage Change in construction payables Other investing activities Net cash used for investing activities Financing Activities: Proceeds — Capital contributions from parent company Pollution control bonds Senior notes issuances Redemptions — Pollution control revenue bonds Senior notes Payment of preferred and preference stock dividends Payment of common stock dividends Other financing activities Net cash used for 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 — Interest (net of $18, $11 and $7 capitalized, respectively) Income taxes (net of refunds) Noncash transactions — accrued property additions at year-end The accompanying notes are an integral part of these financial statements. 29 2014 2013 (in millions) 2012 $ 800 $ 751 $ 743 724 270 (49) (61) 11 17 (58) 61 (17) (11) 157 (199) 50 5 9 1,709 (1,457) (245) 244 (77) (10) (22) (1,567) 28 254 400 (254) — (39) (550) (3) (164) (22) 295 273 231 436 8 $ $ 816 198 (32) 9 10 (38) 2 146 19 5 35 (23) (23) 42 (3) 1,914 (1,107) (280) 279 (47) (13) 26 (1,142) 24 — 300 — (250) (39) (644) (5) (614) 158 137 295 243 296 18 $ $ 767 164 (19) (21) 9 (24) 23 (132) (21) (4) (77) (12) (3) 1 (18) 1,376 (867) (194) 193 (33) 12 (45) (934) 27 — 1,000 (1) (950) (39) (684) (2) (649) (207) 344 137 273 309 31 $ $ BALANCE SHEETS At December 31, 2014 and 2013 Alabama Power Company 2014 Annual Report Assets Current Assets: Cash and cash equivalents 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 regulatory assets, current Other current assets Total current assets Property, Plant, and Equipment: In service Less accumulated provision for depreciation Plant in service, net of 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 Miscellaneous property and investments 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, deferred Other deferred charges and assets Total deferred charges and other assets Total Assets The accompanying notes are an integral part of these financial statements. 30 2014 2013 (in millions) $ 273 $ 295 345 138 74 23 37 (9) 268 406 65 244 84 5 341 142 — 30 54 (8) 329 375 63 57 54 6 1,953 1,738 23,080 8,522 14,558 348 1,006 15,912 66 756 84 906 525 — 31 1,063 162 1,781 $ 20,552 $ 22,092 8,114 13,978 332 748 15,058 54 714 80 848 519 276 25 645 142 1,607 19,251 BALANCE SHEETS At December 31, 2014 and 2013 Alabama Power Company 2014 Annual Report Liabilities and Stockholder's Equity Current Liabilities: Securities due within one year Accounts payable — Affiliated Other Customer deposits Accrued taxes — Accrued income taxes Other accrued taxes Accrued interest Accrued vacation pay Accrued compensation Other regulatory liabilities, current Other current liabilities 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, deferred Deferred over recovered regulatory clause revenues Other deferred credits and liabilities Total deferred credits and other liabilities Total Liabilities Redeemable Preferred Stock (See accompanying statements) 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. 31 2014 2013 (in millions) $ 454 $ 248 443 87 2 37 66 54 131 2 80 1,604 6,176 3,874 72 125 326 829 744 239 47 79 6,335 14,115 342 343 5,752 $ 20,552 $ — 198 339 85 11 33 61 53 74 37 41 932 6,233 3,603 75 133 195 730 828 259 15 61 5,899 13,064 342 343 5,502 19,251 STATEMENTS OF CAPITALIZATION At December 31, 2014 and 2013 Alabama Power Company 2014 Annual Report Long-Term Debt: Long-term debt payable to affiliated trusts — Variable rate (3.36% at 1/1/15) due 2042 Long-term notes payable — 0.55% due 2015 5.20% due 2016 5.50% to 5.55% due 2017 5.13% due 2019 3.375% to 6.125% due 2020-2044 Total long-term notes payable Other long-term debt — Pollution control revenue bonds — 0.28% to 5.00% due 2034 Variable rate (0.03% at 1/1/15) due 2015 Variable rates (0.04% to 0.06% at 1/1/15) due 2017 Variable rates (0.01% to 0.06% at 1/1/15) due 2021-2038 Total other long-term debt Capitalized lease obligations Unamortized debt discount, net Total long-term debt (annual interest requirement — $259 million) Less amount due within one year Long-term debt excluding amount due within one year Redeemable Preferred Stock: Cumulative redeemable 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 (annual dividend requirement — $18 million) Total redeemable preferred stock Preference Stock: Authorized — 40,000,000 shares Outstanding — $1 par value — 5.63% to 6.50% — 14,000,000 shares (noncumulative): $25 stated value (annual dividend requirement — $21 million) Common Stockholder's Equity: Common stock, par value $40 per share — Authorized — 40,000,000 shares Outstanding — 30,537,500 shares Paid-in capital Retained earnings Accumulated other comprehensive loss Total common stockholder's equity Total Capitalization The accompanying notes are an integral part of these financial statements. 32 2014 2013 2014 2013 (in millions) (percent of total) $ 206 $ 206 400 200 525 200 3,950 5,275 367 54 36 694 1,151 5 (7) 6,630 454 6,176 400 200 525 200 3,550 4,875 367 54 36 694 1,151 5 (4) 6,233 — 6,233 48 48 49.0% 50.2% 294 342 294 342 2.7 2.7 343 343 2.7 2.8 1,222 2,304 2,255 (29) 5,752 12,613 $ 1,222 2,262 2,044 (26) 5,502 12,420 $ 45.6 100.0% 44.3 100.0% STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2014, 2013, and 2012 Alabama Power Company 2014 Annual Report Number of Common Shares Issued Common Stock Paid-In Capital Retained Earnings (in millions) Accumulated Other Comprehensive Income (Loss) Total Balance at December 31, 2011 31 $ 1,222 $ 2,182 $ 1,956 $ (18) $ 5,342 — — (9) — (27) — — 1 — (26) 704 45 (9) (684) 5,398 712 35 1 (644) 5,502 — 761 42 — (3) — (550) (29) $ 5,752 (3) Net income after dividends on preferred and preference stock Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Balance at December 31, 2012 Net income after dividends on preferred and preference stock Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Balance at December 31, 2013 Net income after dividends on preferred and preference stock Capital contributions from parent company Other comprehensive income (loss) Cash dividends on common stock Balance at December 31, 2014 — — — — 31 — — — — 31 — — — — 31 — — — — — 45 — — 1,222 2,227 — — — — 1,222 — — — — 35 — — 2,262 — 42 — — 1,222 $ — 2,304 $ $ 704 — — (684) 1,976 712 — — (644) 2,044 761 — — (550) 2,255 $ The accompanying notes are an integral part of these financial statements. 33 NOTES TO FINANCIAL STATEMENTS Alabama Power Company 2014 Annual Report Index to the Notes to Financial Statements Note 1 2 3 4 5 6 7 8 9 10 11 12 Summary of Significant Accounting Polices................................................................................... Retirement Benefits ......................................................................................................................... Contingencies and Regulatory Matters ........................................................................................... Joint Ownership Agreements........................................................................................................... Income Taxes................................................................................................................................... Financing ......................................................................................................................................... Commitments .................................................................................................................................. Stock Compensation........................................................................................................................ Nuclear Insurance............................................................................................................................ Fair Value Measurements ................................................................................................................ Derivatives....................................................................................................................................... Quarterly Financial Information (Unaudited) ................................................................................. Page 35 42 52 56 57 59 62 63 64 65 68 73 34 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Alabama Power Company (the Company) is a wholly owned subsidiary of The Southern Company (Southern Company), which is the parent company of four traditional operating companies, Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – the Company, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, 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 primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system'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 (VIEs) where the Company has an equity investment, but is not the primary beneficiary. The Company is subject to regulation by the FERC and the Alabama PSC. The Company follows GAAP in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. Recently Issued Accounting Standards On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. 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, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs for these services amounted to $400 million, $340 million, and $340 million during 2014, 2013, and 2012, respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC 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 the following nuclear-related services are rendered to the Company at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, employee relations, systems and procedures services, strategic planning and budgeting services, and other services with respect to business and operations. Costs for these services amounted to $234 million, $211 million, and $218 million during 2014, 2013, and 2012, 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 $13 million in 2014, $13 million in 2013, and $12 million in 2012. Also, Mississippi Power reimburses the Company for any direct fuel purchases delivered from one of the Company's transfer facilities, which were $34 million in 2014, $27 million in 2013, and $28 million in 2012. See Note 4 for additional information. The Company has an agreement with Gulf Power under which the Company has made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA. In 2009, Gulf Power entered into a PPA for the capacity and energy from a combined cycle plant located in Autauga County, Alabama. The total cost committed by the Company related to the upgrades is approximately $85 million, of which approximately $29 million was spent in 2014. The transmission improvements were completed in 2014. The Company expects to recover a majority of these costs through a tariff with Gulf Power until 2023. The remainder of these costs will be recovered through normal rate mechanisms. 35 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2014, 2013, or 2012. Also, see Note 4 for information regarding the Company's ownership in a PPA and a gas pipeline ownership agreement with SEGCO. The traditional operating companies, including the Company and Southern Power, may 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 and Purchased Power Agreements" for additional information. 36 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report Regulatory Assets and Liabilities The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: Deferred income tax charges Loss on reacquired debt Vacation pay Under/(over) recovered regulatory clause revenues Fuel-hedging losses Other regulatory assets Asset retirement obligations Other cost of removal obligations Deferred income tax credits Fuel-hedging gains Nuclear outage Natural disaster reserve Other regulatory liabilities Retiree benefit plans Regulatory deferrals Nuclear fuel disposal fee Total regulatory assets (liabilities), net 2014 2013 (in millions) $ $ 525 80 65 57 53 49 (125) (744) (72) (1) 56 (84) (8) 882 13 (8) 738 $ $ 519 86 63 (18) 8 52 (132) (828) (75) (8) 51 (96) (11) 461 20 — 92 Note (a,k) (b) (c,j) (d) (e) (f) (a) (a) (a) (e) (d) (h) (d,g) (i,j) (l) (m) Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: (a) Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal assets and 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 over periods not exceeding 10 years. (e) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause. (f) Comprised of components including generation site selection/evaluation costs, PPA capacity, and other miscellaneous assets. Recorded as accepted by the Alabama PSC. Capitalized upon initialization of related construction projects, if applicable. (g) Comprised of components including mine reclamation and remediation liabilities and other liabilities. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities. (h) Utilized as storm restoration and potential reliability-related expenses are incurred, as approved by the Alabama PSC. (i) Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. (j) Not earning a return as offset in rate base by a corresponding asset or liability. (k) Included in the deferred income tax charges are $18 million for 2014 and $20 million for 2013 for the retiree Medicare drug subsidy, which is recovered and amortized, as approved by the Alabama PSC, over the average remaining service period which may range up to 15 years. (l) Recorded and amortized as approved by the Alabama PSC for a period of five years. (m) Recorded as approved by the Alabama PSC related to potential future fees for nuclear waste disposal. The term of deferral is conditional upon resolution by the DOE. See Note 3 for additional information. In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any 37 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report 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. See Note 3 under "Retail Regulatory Matters" for additional information. Revenues Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales 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 – Rate ECR" and "Retail Regulatory Matters – Rate CNP" for additional information. The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions 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 "Retail Regulatory Matters – Nuclear Waste Fund Fee Accounting Order" 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. Federal ITCs 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 accounting standards related to the uncertainty in income taxes, 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 any 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 cost of equity funds used during construction. The Company's property, plant, and equipment in service consisted of the following at December 31: Generation Transmission Distribution General Plant acquisition adjustment Total plant in service 2014 2013 (in millions) $ 11,670 $ 11,314 3,579 6,196 1,623 12 3,287 5,934 1,545 12 $ 23,080 $ 22,092 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 other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific Alabama PSC orders. 38 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report Nuclear Outage Accounting Order In accordance with an Alabama PSC order, nuclear outage operations and maintenance expenses for the two units at Plant Farley are deferred to a regulatory asset when the charges actually occur and are then amortized over a subsequent 18-month period with the fall outage costs amortization beginning in January of the following year and the spring outage costs amortization beginning in July of the same year. Depreciation and Amortization Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.3% in 2014 and 3.2% in 2013 and 2012. Depreciation studies are conducted periodically to update the composite rates and the information is provided to the Alabama PSC and the FERC. When property subject to composite 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 are 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. In 2014, the Company submitted a depreciation study to the FERC and received authorization to use the recommended rates beginning January 2015. The study was also provided to the Alabama PSC. Asset Retirement Obligations and Other Costs of Removal Asset retirement obligations (ARO) 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 are reflected in the balance sheets as a regulatory liability. The liability for AROs primarily relates to the decommissioning of the Company's nuclear facility, Plant Farley. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal, disposal of polychlorinated biphenyls in certain transformers, and disposal of sulfur hexafluoride gas in certain substation breakers. 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 settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. 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 in accordance with accounting standards related to asset retirement and environmental 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" herein for additional information on amounts included in rates. Details of the AROs included in the balance sheets are as follows: Balance at beginning of year Liabilities incurred Liabilities settled Accretion Cash flow revisions Balance at end of year 2014 2013 (in millions) $ 730 $ 589 1 (3) 45 56 $ 829 $ — (1) 40 102 730 The cash flow revisions in 2014 are primarily related to the Company's AROs associated with asbestos at its steam generation facilities. The cash flow revisions in 2013 are primarily related to revisions to the nuclear decommissioning ARO based on the Company's updated decommissioning study. On December 19, 2014, the EPA issued the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), but has not yet published it in the Federal Register. The CCR Rule will regulate the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in landfills and surface impoundments at active generating power plants. The ultimate 39 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report impact of the CCR Rule cannot be determined at this time and will depend on the Company's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. The cost and timing of potential ash pond closure and ongoing monitoring activities that may be required in connection with the CCR Rule is also uncertain; however, the Company has developed a preliminary nominal dollar estimate of costs associated with closure and groundwater monitoring of ash ponds in place of approximately $311 million and ongoing post-closure care of approximately $49 million. The Company will record AROs for the estimated closure costs required under the CCR Rule during 2015. SEGCO, which is jointly owned with Georgia Power, will also record an ARO for ash ponds commonly used at Plant E.C. Gaston. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. Nuclear Decommissioning The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The Company has external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the Alabama PSC, as well as the IRS. While the Company is allowed to prescribe an overall investment policy to the Funds' managers, the Company and its affiliates are not allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the management of the Company. The Funds' managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities. The Company records the investment securities held in the Funds at fair value, as disclosed in Note 10, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis. At December 31, 2014, investment securities in the Funds totaled $754 million, consisting of equity securities of $583 million, debt securities of $163 million, and $8 million of other securities. At December 31, 2013, investment securities in the Funds totaled $713 million, consisting of equity securities of $566 million, debt securities of $131 million, and $16 million of other securities. These amounts exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases. Sales of the securities held in the Funds resulted in cash proceeds of $244 million, $279 million, and $193 million in 2014, 2013, and 2012, respectively, all of which were reinvested. For 2014, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $54 million, of which $2 million related to realized gains and $19 million related to unrealized gains related to securities held in the Funds at December 31, 2014. For 2013, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $120 million, of which $5 million related to realized gains and $85 million related to unrealized gains related to securities held in the Funds at December 31, 2013. For 2012, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $70 million, of which $4 million related to realized gains and $50 million related to unrealized losses related to securities held in the Funds at December 31, 2012. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired. Amounts previously recorded in internal reserves are being transferred into the 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 Funds will provide the minimum funding amounts prescribed by the NRC. 40 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report At December 31, the accumulated provisions for decommissioning were as follows: External trust funds Internal reserves Total 2014 2013 (in millions) $ $ $ 754 21 775 713 21 734 Site study costs is the estimate to decommission a facility as of the site study year. The estimated costs of decommissioning as of December 31, 2014 based on the most current study performed in 2013 for Plant Farley are as follows: Decommissioning periods: Beginning year Completion year Site study costs: Radiated structures Non-radiated structures Total site study costs 2037 2076 (in millions) $ $ 1,362 80 1,442 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%. The next site study is expected to be conducted in 2018. Amounts previously contributed to the Funds 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 NRC and other applicable requirements. Allowance for Funds Used During Construction 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, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. All current construction costs are included in retail rates. The AFUDC composite rate as of December 31 was 8.8% in 2014, 9.1% in 2013, and 9.4% in 2012. AFUDC, net of income taxes, as a percent of net income after dividends on preferred and preference stock was 7.9% in 2014, 5.4% in 2013, and 3.3% in 2012. 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. 41 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Materials and Supplies Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. Fuel Inventory Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the Company through energy cost recovery rates approved by the Alabama PSC. Emissions allowances granted by the 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 (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the Alabama PSC-approved fuel-hedging program result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. If any, immaterial ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information regarding derivatives. 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 had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2014. 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. 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 reclassifications for amounts included in net income. Variable Interest Entities The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. The Company has established a wholly-owned trust to issue preferred securities. See Note 6 under "Long-Term Debt Payable to an Affiliated Trust" for additional information. However, the Company is not considered the primary beneficiary of the trust. Therefore, the investment in the trust is reflected as other investments, and the related loan from the trust is reflected as long-term debt in the balance sheets. 2. RETIREMENT BENEFITS The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions were made to the qualified pension plan during 2014. No mandatory contributions to the qualified pension plan 42 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report are anticipated for the year ending December 31, 2015. 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 its other postretirement trusts to the extent required by the Alabama PSC and the FERC. For the year ending December 31, 2015, other postretirement trusts contributions are expected to total approximately $2 million. 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 2011 for the 2012 plan year using discount rates for the pension plans and the other postretirement benefit plans of 4.98% and 4.88%, respectively, and an annual salary increase of 3.84%. Discount rate: Pension plans Other postretirement benefit plans Annual salary increase Long-term return on plan assets: Pension plans Other postretirement benefit plans 2014 2013 2012 4.18% 4.04 3.59 8.20 7.34 5.02% 4.86 3.59 8.20 7.36 4.27% 4.06 3.59 8.20 7.19 The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio. For purposes of its December 31, 2014 measurement date, the Company adopted new mortality tables for its pension plans and retiree life and medical plans, which reflect increased life expectancies in the U.S. The adoption of new mortality tables increased the projected benefit obligations for the Company's pension plans and other postretirement benefit plans by approximately $156 million and $22 million, respectively. An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2014 were as follows: Pre-65 Post-65 medical Post-65 prescription Initial Cost Trend Rate 9.00% 6.00 6.75 Ultimate Cost Trend Rate 4.50% 4.50 4.50 Year That Ultimate Rate is Reached 2024 2024 2024 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, 2014 as follows: Benefit obligation Service and interest costs 1 Percent Increase 1 Percent Decrease $ (in millions) $ 34 1 (29) (1) 43 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report Pension Plans The total accumulated benefit obligation for the pension plans was $2.4 billion at December 31, 2014 and $1.9 billion at December 31, 2013. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: Change in benefit obligation Benefit obligation at beginning of year Service cost Interest cost Benefits paid Actuarial (gain) loss Balance at end of year Change in plan assets Fair value of plan assets at beginning of year Actual return on plan assets Employer contributions Benefits paid Fair value of plan assets at end of year Prepaid pension costs (accrued liability) 2014 2013 (in millions) $ 2,112 $ 2,218 48 103 (100) 429 2,592 2,278 207 11 (100) 2,396 (196) $ 52 93 (93) (158) 2,112 2,077 285 9 (93) 2,278 166 $ At December 31, 2014, the projected benefit obligations for the qualified and non-qualified pension plans were $2.5 billion and $123 million, respectively. All pension plan assets are related to the qualified pension plan. Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's pension plans consist of the following: Prepaid pension costs Other regulatory assets, deferred Other current liabilities Employee benefit obligations 2014 2013 (in millions) $ — 827 (10) (186) $ 276 476 (9) (101) Presented below are the amounts included in regulatory assets at December 31, 2014 and 2013 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 2015. Prior service cost Net (gain) loss Regulatory assets 2014 $ $ 12 815 827 2013 (in millions) $ $ 19 457 476 Estimated Amortization in 2015 $ 6 55 44 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2014 and 2013 are presented in the following table: 2014 2013 (in millions) Regulatory assets: Beginning balance Net (gain) loss Reclassification adjustments: Amortization of prior service costs Amortization of net gain (loss) Total reclassification adjustments Total change Ending balance Components of net periodic pension cost were as follows: Service cost Interest cost Expected return on plan assets Recognized net (gain) loss Net amortization Net periodic pension cost $ $ 476 389 (7) (31) (38) 351 827 2014 2013 (in millions) $ $ 48 103 (168) 31 7 21 $ $ 52 93 (157) 52 7 47 $ $ $ $ 822 (287) (7) (52) (59) (346) 476 2012 44 94 (162) 23 7 6 Net periodic pension cost 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, 2014, estimated benefit payments were as follows: 2015 2016 2017 2018 2019 2020 to 2024 Benefit Payments (in millions) $ 127 114 120 125 129 708 45 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report Other Postretirement Benefits Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2014 and 2013 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 on plan assets Employer contributions Benefits paid Fair value of plan assets at end of year Accrued liability 2014 2013 (in millions) $ $ 431 5 20 (27) 71 3 503 389 23 4 (24) 392 (111) $ $ 490 6 19 (24) (62) 2 431 343 61 7 (22) 389 (42) Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's other postretirement benefit plans consist of the following: Other regulatory assets, deferred Other regulatory liabilities, deferred Employee benefit obligations 2014 2013 (in millions) $ 68 (14) (111) $ 6 (21) (42) 46 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2014 and 2013 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2015. Prior service cost Net (gain) loss Net regulatory assets (liabilities) 2014 $ $ 15 39 54 2013 (in millions) $ $ 19 (34) (15) Estimated Amortization in 2015 $ 4 2 The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2014 and 2013 are presented in the following table: 2014 2013 (in millions) Net regulatory assets (liabilities): Beginning balance Net gain (loss) Reclassification adjustments: Amortization of prior service costs Amortization of net gain (loss) Total reclassification adjustments Total change Ending balance $ $ (15) 73 (4) — (4) 69 54 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 periodic postretirement benefit cost 2014 2013 (in millions) $ $ 5 20 (25) 4 4 $ $ 6 19 (23) 5 7 $ $ $ $ 89 (99) (3) (2) (5) (104) (15) 2012 5 22 (23) 6 10 Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows: 2015 2016 2017 2018 2019 2020 to 2024 Benefit Plan Assets Benefit Payments $ 31 32 32 34 34 172 Subsidy Receipts (in millions) $ (3) (3) (4) (4) (4) (22) $ Total 28 29 28 30 30 150 Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended. The Company's investment policies for 47 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2014 and 2013, along with the targeted mix of assets for each plan, is presented below: Target 2014 2013 Pension plan assets: Domestic equity International equity Fixed income Special situations Real estate investments Private equity Total Other postretirement benefit plan assets: Domestic equity International equity Domestic fixed income Special situations Real estate investments Private equity Total 26% 25 23 3 14 9 100% 48% 20 24 1 4 3 30% 23 27 1 14 5 100% 48% 20 26 — 4 2 31% 25 23 1 14 6 100% 47% 20 27 — 4 2 100% 100% 100% The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Investment Strategies Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above: • Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches. • International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches. • Fixed income. A mix of domestic and international bonds. • Trust-owned life insurance (TOLI). Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio. • Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature. • Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. • Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. 48 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report Benefit Plan Asset Fair Values Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2014 and 2013. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. Valuation methods of the primary fair value measurements disclosed in the following tables are as follows: • Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities. • Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. • TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities. • Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets. The fair values of pension plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. As of December 31, 2014: Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Real estate investments Private equity Total Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in millions) Total $ $ 421 264 — — — — 1 73 — $ 174 244 173 47 280 127 163 — — $ 759 $ 1,208 $ — — — — — — — 277 141 418 $ 595 508 173 47 280 127 164 350 141 $ 2,385 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well- diversified with no significant concentrations of risk. 49 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report As of December 31, 2013: Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Real estate investments Private equity Total Liabilities: Derivatives Total Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in millions) Total $ $ $ $ 374 287 — — — — — 68 — 729 — 729 $ $ $ $ 219 265 156 41 255 123 58 — — 1,117 (1) 1,116 $ $ $ $ — — — — — — — 261 149 410 — 410 $ $ $ $ 593 552 156 41 255 123 58 329 149 2,256 (1) 2,255 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well- diversified with no significant concentrations of risk. Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: 2014 2013 Real Estate Investments Private Equity Real Estate Investments Private Equity Beginning balance Actual return on investments: Related to investments held at year end Related to investments sold during the year Total return on investments Purchases, sales, and settlements Ending balance $ $ 261 6 8 14 2 277 (in millions) $ 149 $ 5 (4) 1 (9) 141 $ $ 220 19 8 27 14 261 $ 155 2 13 15 (21) 149 $ The fair values of other postretirement benefit plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. 50 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report As of December 31, 2014: Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Trust-owned life insurance Real estate investments Private equity Total Quoted Prices in Active Markets for Identical Assets (Level 1) Fair Value Measurements Using Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in millions) 8 12 10 2 14 6 8 217 — — 277 $ $ 76 13 — — — — — — 5 — 94 $ $ — — — — — — — — 13 7 20 $ $ $ $ Total 84 25 10 2 14 6 8 217 18 7 391 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well- diversified with no significant concentrations of risk. As of December 31, 2013: Assets: Domestic equity* International equity* Fixed income: U.S. Treasury, government, and agency bonds Mortgage- and asset-backed securities Corporate bonds Pooled funds Cash equivalents and other Trust-owned life insurance Real estate investments Private equity Total Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in millions) Total $ $ 67 14 — — — — — — 4 — 85 $ $ 11 13 17 2 12 6 10 211 — — 282 $ $ — — — — — — — — 13 7 20 $ $ 78 27 17 2 12 6 10 211 17 7 387 * Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well- diversified with no significant concentrations of risk. Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: 51 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report 2014 2013 Real Estate Investments Private Equity Real Estate Investments Private Equity $ $ 13 — — — — 13 $ $ (in millions) 7 — — — — 7 $ $ 11 1 — 1 1 13 $ $ 8 — — — (1) 7 Beginning balance Actual return on investments: Related to investments held at year end Related to investments sold during the year Total return on investments Purchases, sales, and settlements Ending balance Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2014, 2013, and 2012 were $21 million, $20 million, and $19 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, such as regulation of air emissions and water discharges. 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 air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. 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 ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. Environmental Matters New Source Review Actions As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against the Company alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including a unit co-owned by Mississippi Power. These civil actions seek penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against the Company (including claims involving a unit co-owned by Mississippi Power) has been actively litigated in the U.S. District Court for the Northern District of Alabama, resulting in a settlement in 2006 of the alleged NSR violations at Plant Miller; voluntary dismissal of certain claims by the EPA; and a grant of summary judgment for the Company on all remaining claims and dismissal of the case with prejudice in 2011. In September 2013, the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment in favor of the Company, and the case has been transferred back to the U.S. District Court for the Northern District of Alabama for further proceedings. The Company believes it complied with applicable laws and regulations 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, depending on the date of the alleged violation. An adverse outcome could require substantial 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. The ultimate outcome of this matter cannot be determined at this time. Environmental Remediation The Company must comply with 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 52 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report 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. Nuclear Fuel Disposal Costs Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into a contract with the Company that requires the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plant Farley beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, the Company has pursued and continues to pursue legal remedies against the U.S. government for its partial breach of contract. As a result of the first lawsuit, the Company recovered approximately $17 million, representing the vast majority of the Company's direct costs of the expansion of spent nuclear fuel storage facilities at Plant Farley from 1998 through 2004. In 2012, the award was credited to cost of service for the benefit of customers. On December 12, 2014, the Court of Federal Claims entered a judgment in favor of the Company in its second spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. The Company was awarded approximately $26 million. No amounts have been recognized in the financial statements as of December 31, 2014. The final outcome of this matter cannot be determined at this time; however, no material impact on the Company's net income is expected. On March 4, 2014, the Company filed a third lawsuit against the U.S. government for the costs of continuing to store spent nuclear fuel at Plant Farley for the period from January 1, 2011 through December 31, 2013. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2014 for any potential recoveries from the third lawsuit. The final outcome of this matter cannot be determined at this time; however, no material impact on the Company's net income is expected. At Plant Farley, on-site dry spent fuel storage facilities are operational and can be expanded to accommodate spent fuel through the expected life of the plant. Retail Regulatory Matters Rate RSE 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 4.0% and any annual adjustment is limited to 5.0%. If the Company's actual retail return is above the allowed weighted cost of equity (WCE) range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range. Prior to 2014, retail rates remained unchanged when the retail ROE was projected to be between 13.0% and 14.5%. During 2013, the Alabama PSC held public proceedings regarding the operation and utilization of Rate RSE. In August 2013, the Alabama PSC voted to issue a report on Rate RSE that found that the Company's Rate RSE mechanism continues to be just and reasonable to customers and the Company, but recommended the Company modify Rate RSE as follows: • Eliminate the provision of Rate RSE establishing an allowed range of ROE. • Eliminate the provision of Rate RSE limiting the Company's capital structure to an allowed equity ratio of 45%. • Replace these two provisions with a provision that establishes rates based upon the WCE range of 5.75% to 6.21%, with an adjusting point of 5.98%. If calculated under the previous Rate RSE provisions, the resulting WCE would range from 5.85% to 6.53%, with an adjusting point of 6.19%. • Provide eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if the Company (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one- third of a designated customer value benchmark survey. Substantially all other provisions of Rate RSE were unchanged. In August 2013, the Company filed its consent to these recommendations with the Alabama PSC. The changes became effective for calendar year 2014. In November 2013, the Company made its Rate RSE submission to the Alabama PSC of projected data for calendar year 2014; projected earnings were within the specified WCE range and, therefore, retail rates under Rate RSE remained unchanged for 2014. In 2012 and 2013, retail rates under Rate RSE remained unchanged from 2011. Under the terms of Rate RSE, the maximum possible increase for 2015 is 5.00%. 53 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report On December 1, 2014, the Company submitted the required annual filing under Rate RSE to the Alabama PSC. The Rate RSE increase was 3.49%, or $181 million annually, effective January 1, 2015. The revenue adjustment includes the performance based adder of 0.07%. Under the terms of Rate RSE, the maximum increase for 2016 cannot exceed 4.51%. 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 under Rate CNP. The Company may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 4, 2014, the Alabama PSC issued a consent order that the Company leave in effect the current Rate CNP PPA factor for billings for the period April 1, 2014 through March 31, 2015. It is anticipated that no adjustment will be made to Rate CNP PPA in 2015. As of December 31, 2014, the Company had an under recovered certificated PPA balance of $56 million, of which $27 million is included in under recovered regulatory clause revenues and $29 million is included in deferred under recovered regulatory clause revenues in the balance sheet. In 2011, the Alabama PSC approved and certificated a PPA of approximately 200 MWs of electricity from wind-powered generating facilities that became operational in 2012. In 2012, the Alabama PSC approved and certificated a second PPA of approximately 200 MWs of electricity from other wind-powered generating facilities which became operational in 2014. The terms of the PPAs permit the Company to use the energy and retire the associated environmental attributes in service of its customers or to sell the environmental attributes, separately or bundled with energy. The Company has elected the normal purchase normal sale (NPNS) scope exception under the derivative accounting rules for its two wind PPAs, which total approximately 400 MWs. The NPNS exception allows the PPAs to be recorded at a cost, rather than fair value, basis. The industry's application of the NPNS exception to certain physical forward transactions in nodal markets was previously under review by the SEC at the request of the electric utility industry. In June 2014, the SEC requested the Financial Accounting Standards Board to address the issue through the Emerging Issues Task Force (EITF). Any accounting decisions will now be subject to EITF deliberations. The outcome of the EITF's deliberations cannot be determined at this time. If the Company is ultimately required to record these PPAs at fair value, an offsetting regulatory asset or regulatory liability will be recorded. Rate CNP Environmental allows for the recovery of the Company's retail costs associated with environmental laws, regulations, or other such mandates. Rate CNP Environmental 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 certain invested capital. There was no adjustment to Rate CNP Environmental in 2014. In August 2013, the Alabama PSC approved the Company's petition requesting a revision to Rate CNP Environmental that allows recovery of costs related to pre-2005 environmental assets previously being recovered through Rate RSE. The Rate CNP Environmental increase effective January 1, 2015 was 1.5%, or $75 million annually, based upon projected billings. As of December 31, 2014, the Company had an under recovered environmental clause balance of $49 million, of which $47 million is included in under recovered regulatory clause revenues and $2 million is included in deferred under recovered regulatory clause revenues in the balance sheet. Rate ECR The Company has established energy cost recovery rates under the Company's Rate ECR as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. The Company, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on the Company's net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH. In December 2014, the Alabama PSC issued a consent order that the Company leave in effect for 2015 the energy cost recovery rates which began in 2011. Therefore, the Rate ECR factor as of January 1, 2015 remained at 2.681 cents per KWH. Effective with billings beginning in January 2016, the Rate ECR factor will be 5.910 cents per KWH, absent a further order from the Alabama PSC. The Company's over recovered fuel costs at December 31, 2014 totaled $47 million as compared to over recovered fuel costs of $42 million at December 31, 2013. At December 31, 2014, $47 million is included in deferred over recovered regulatory clause revenues. These classifications are based on estimates, which include 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 any recovery or return of fuel costs. Rate NDR Based on an order from 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. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a 54 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report reserve balance for future storms and is an on-going part of customer billing. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. The Company has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. The Company may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance the Company's ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows. Environmental Accounting Order Based on an order from the Alabama PSC, the Company is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. These costs would be amortized over the affected unit's remaining useful life, as established prior to the decision regarding early retirement. As part of its environmental compliance strategy, the Company plans to retire Plant Gorgas Units 6 and 7. These units represent 200 MWs of the Company's approximately 12,200 MWs of generating capacity. The Company also plans to cease using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. Additionally, the Company expects to cease using coal at Plant Barry Unit 3 (225 MWs) and Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. These plans are expected to be effective no later than April 2016. In accordance with an accounting order from the Alabama PSC, the Company will transfer the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized through Rate CNP Environmental over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on the Company's financial statements. Nuclear Waste Fund Accounting Order In November 2013, the U.S. District Court for the District of Columbia ordered the DOE to cease collecting spent fuel depositary fees from nuclear power plant operators until such time as the DOE either complies with the Nuclear Waste Policy Act of 1982 or until the U.S. Congress enacts an alternative waste management plan. In accordance with the court's order, the DOE submitted a proposal to the U.S. Congress to change the fee to zero. On March 18, 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied the DOE's request for rehearing of the November 2013 panel decision ordering that the DOE propose the nuclear waste fund fee be changed to zero. The DOE formally set the fee to zero effective May 16, 2014. On August 5, 2014, the Alabama PSC issued an order to provide for the continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. In accordance with the order, effective May 16, 2014, the Company is authorized to recover from customers an amount equal to the prior fee and to record the amounts in a regulatory liability account (approximately $14 million annually). At December 31, 2014, the Company recorded an $8 million regulatory liability which is included in other regulatory liabilities deferred in the balance sheet. Upon the DOE meeting the requirements of the Nuclear Waste Policy Act of 1982 and a new spent fuel depositary fee being put in place, the accumulated balance in the regulatory liability account will be available for purposes of the associated cost responsibility. In the event the balance is later determined to be more than needed, those amounts would be used for the benefit of customers, subject to the approval of the Alabama PSC. The ultimate outcome of this matter cannot be determined at this time. Compliance and Pension Cost Accounting Order In 2012, the Alabama PSC approved an accounting order to defer to a regulatory asset account certain compliance-related operations and maintenance expenditures for the years 2013 through 2017, as well as the incremental increase in operations expense related to pension cost for 2013. These deferred costs would have been amortized over a three-year period beginning in January 2015. The compliance related expenditures were related to (i) standards addressing Critical Infrastructure Protection issued by the North American Electric Reliability Corporation, (ii) cyber security requirements issued by the NRC, and (iii) NRC guidance addressing the readiness at nuclear facilities within the U.S. for severe events. 55 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report On November 3, 2014, the Alabama PSC issued an accounting order authorizing the Company to fully amortize the balances in certain regulatory asset accounts, including the $28 million of compliance and pension costs accumulated at December 31, 2014. This amortization expense was offset by the amortization of the regulatory liability for other cost of removal obligations. See "Cost of Removal Accounting Order" herein for additional information. The cost of removal accounting order requires the Company to terminate, as of December 31, 2014, the regulatory asset accounts created pursuant to the compliance and pension cost accounting order. Consequently, the Company will not defer any expenditures in 2015, 2016, and 2017 related to critical electric infrastructure and domestic nuclear facilities under these orders. Non-Nuclear Outage Accounting Order In August 2013, the Alabama PSC approved an accounting order to defer to a regulatory asset account certain operations and maintenance expenses associated with planned outages at non-nuclear generation facilities in 2014 and to amortize those expenses over a three-year period beginning in 2015. On November 3, 2014, the Alabama PSC issued an accounting order authorizing the Company to fully amortize the balances in certain regulatory asset accounts, including the $95 million of non-nuclear outage costs accumulated at December 31, 2014. This amortization expense was reflected in other operations and maintenance and was offset by the amortization of the regulatory liability for other cost of removal obligations. See "Cost of Removal Accounting Order" herein for additional information. The cost of removal accounting order requires the Company to terminate, as of December 31, 2014, the regulatory asset accounts created pursuant to the non-nuclear outage accounting order. Cost of Removal Accounting Order In accordance with an accounting order issued on November 3, 2014 by the Alabama PSC, at December 31, 2014, the Company fully amortized the balance of $123 million in certain regulatory asset accounts and offset this amortization expense with the amortization of $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset account balances amortized as of December 31, 2014 represented costs previously deferred under a compliance and pension cost accounting order as well as a non-nuclear outage accounting order, as discussed herein. Non-Environmental Federal Mandated Costs Accounting Order On December 9, 2014, pending the development of a new cost recovery mechanism, the Alabama PSC issued an accounting order authorizing the deferral as a regulatory asset of up to $50 million of costs associated with non-environmental federal mandates that would otherwise impact rates in 2015. On February 17, 2015, the Company filed a proposed modification to Rate CNP Environmental with the Alabama PSC to include compliance costs for both environmental and non-environmental mandates. The non-environmental costs that would be recovered through the revised mechanism concern laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting the Company's facilities or operations. If approved as requested, the effective date for the revised mechanism would be March 20, 2015, upon which the regulatory asset balance would be reclassified to the under recovered balance for Rate CNP Environmental, and the related customer rates would not become effective before January 2016. The ultimate outcome of this matter cannot be determined at this time. 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 MWs, as well as associated transmission facilities. The capacity of these units is sold equally to the Company and Georgia Power under a power contract. The Company and Georgia Power make payments sufficient to provide for the operating expenses, taxes, interest expense, and ROE. The Company's share of purchased power totaled $84 million in 2014, $88 million in 2013, and $109 million in 2012 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 $25 million principal amount of pollution control revenue bonds are outstanding. The Company has guaranteed $100 million principal amount of unsecured senior notes issued by SEGCO for general corporate purposes. These senior notes mature on December 1, 2018. The Company had guaranteed $50 million principal amount of unsecured senior notes issued by SEGCO for general corporate purposes, which matured on May 15, 2013. 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 guarantee. 56 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report At December 31, 2014, the capitalization of SEGCO consisted of $106 million of equity and $125 million of long-term debt on which the annual interest requirement is $3 million. In addition, SEGCO had short-term debt outstanding of $42 million. SEGCO paid dividends of $3 million in 2014, $7 million in 2013, and $14 million in 2012, of which one-half of each was paid to the Company. In addition, the Company recognizes 50% of SEGCO's net income. SEGCO plans to add natural gas as the primary fuel source for 1,000 MWs of its generating capacity in 2015. A natural gas pipeline was constructed and will be placed in service in 2015. The Company, which owns and operates a generating unit adjacent to the SEGCO generating units, has entered into a joint ownership agreement with SEGCO for the ownership of the gas pipeline. The Company will own 14% of the pipeline with the remaining 86% owned by SEGCO. At December 31, 2014, the Company's portion of the construction work in progress associated with the pipeline is $15 million. In addition to the Company's ownership of SEGCO and joint ownership of the natural gas pipeline, the Company's percentage ownership and investment in jointly-owned coal-fired generating plants at December 31, 2014 were as follows: Facility Greene County Plant Miller Units 1 and 2 Total MW Capacity Company Ownership Plant in Service 60.00% (1) $ 164 Accumulated Depreciation (in millions) 96 $ 91.84% (2) 1,512 561 500 1,320 Construction Work in Progress $ 1 14 (1) Jointly owned with an affiliate, Mississippi Power. (2) Jointly owned with PowerSouth Energy Cooperative, Inc. 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 On behalf of the Company, Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Alabama, Georgia, and Mississippi. In addition, the Company files a separate company income tax return for the State of Tennessee. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current 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 federal tax liability. Current and Deferred Income Taxes Details of income tax provisions are as follows: Federal — Current Deferred State — Current Deferred Total 2014 2013 (in millions) 2012 $ $ 198 225 423 44 45 89 512 $ $ 243 160 403 36 39 75 478 $ $ 262 137 399 51 27 78 477 57 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 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 Employee benefit obligations 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 Unbilled fuel revenue Storm reserve Employee benefit obligations Other comprehensive losses Asset retirement obligations Other Total Total deferred tax liabilities, net Portion included in current assets/(liabilities), net Accumulated deferred income taxes 2014 2013 (in millions) $ 3,429 $ 3,187 457 30 215 366 59 285 156 458 33 209 198 38 265 128 4,997 4,516 219 42 27 400 19 344 90 1,141 3,856 18 205 41 32 231 18 303 108 938 3,578 25 $ 3,874 $ 3,603 The application of bonus depreciation provisions in current tax law has significantly increased deferred tax liabilities related to accelerated depreciation. At December 31, 2014, the tax-related regulatory assets to be recovered from customers were $526 million. These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest. At December 31, 2014, the tax-related regulatory liabilities to be credited to customers were $72 million. These liabilities are primarily attributable to unamortized ITCs. In accordance with regulatory requirements, deferred federal ITCs are amortized over the average life 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 million in 2014, 2013 and 2012. At December 31, 2014, all ITCs available to reduce federal income taxes payable had been utilized. 58 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report 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 Other Effective income tax rate Unrecognized Tax Benefits 2014 35.0% 4.4 1.1 (0.1) (1.3) (0.1) 39.0% 2013 35.0% 4.0 1.0 (0.1) (0.9) (0.1) 38.9% 2012 35.0% 4.1 0.9 (0.1) (0.5) (0.3) 39.1% The Company had no unrecognized tax benefits during 2014. Changes in unrecognized tax benefits in prior years were as follows: Unrecognized tax benefits at beginning of year Tax positions from current periods Tax positions from prior periods Reductions due to settlements Balance at end of year 2013 2012 (in millions) $ $ 31 — (31) — — $ $ 32 5 (4) (2) 31 The decrease in tax positions from prior periods for 2013 relates primarily to the tax accounting method change for repairs- generation assets, which did not impact the effective tax rate. See "Tax Method of Accounting for Repairs" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact. The Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial for all periods presented. The Company did not accrue any penalties on uncertain tax positions. The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 federal income tax return and has received a partial acceptance letter from the IRS; however, the IRS has not finalized its audit. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2010. Tax Method of Accounting for Repairs In 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2014. Additionally, in April 2013, the IRS issued Revenue Procedure 2013-24, which provides guidance for taxpayers related to the deductibility of repair costs associated with generation assets. Based on a review of the regulations, Southern Company incorporated provisions related to repair costs for generation assets into its consolidated 2012 federal income tax return and reversed all related unrecognized tax positions. In September 2013, the IRS issued Treasury Decision 9636, "Guidance Regarding Deduction and Capitalization of Expenditures Related to Tangible Property," which are final tangible property regulations applicable to taxable years beginning on or after January 1, 2014. Southern Company continues to review this guidance; however, these regulations are not expected to have a material impact on the Company's financial statements. 6. FINANCING Long-Term Debt Payable to an Affiliated Trust The Company has formed a wholly-owned trust subsidiary 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 as of December 31, 2014 and 2013, which constitute substantially all of the assets of 59 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report this trust 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 trust's payment obligations with respect to these securities. At each of December 31, 2014 and 2013, trust preferred securities of $200 million were outstanding. See Note 1 under "Variable Interest Entities" for additional information on the accounting treatment for this trust and the related securities. Securities Due Within One Year At December 31, 2014, the Company had $454 million of senior notes and pollution control revenue bonds due within one year. At December 31, 2013, the Company had no scheduled maturities of senior notes or pollution control revenue bonds due within one year. Maturities of senior notes and pollution control revenue bonds through 2019 applicable to total long-term debt are as follows: $454 million in 2015; $200 million in 2016; $561 million in 2017; and $200 million in 2019. There are no scheduled maturities in 2018. Subsequent to December 31, 2014, the Company announced the redemption of $250 million aggregate principal amount of its Series DD 5.65% Senior Notes due March 15, 2035 that will occur on March 16, 2015. Pollution Control Revenue Bonds Pollution control obligations represent loans to the Company from public authorities of funds or installment purchases of pollution control and 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. In December 2014, the Company incurred obligations related to the issuance of $254 million of The Industrial Development Board of the Town of Columbia, Pollution Control Revenue Refunding Bonds (Alabama Power Company Project), Series 2014 – A, Series 2014 – B, Series 2014 – C, and Series 2014 – D due December 1, 2037. The proceeds were used to refund in December 2014 approximately $254 million of The Industrial Development Board of the Town of Columbia, Pollution Control Revenue Refunding Bonds (Alabama Power Company Project), Series 1995 – A, 1995 – B, 1995 – C, 1995 – D, 1995 – E, 1996 – A, 1999 – A, 1999 – B, and 1999 – C. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2014 and 2013 was $1.2 billion, respectively. Senior Notes In August 2014, the Company issued $400 million aggregate principal amount of Series 2014A 4.150% Senior Notes due August 15, 2044. The proceeds were used for general corporate purposes, including the Company's continuous construction program. During 2014, the Company entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $200 million. At December 31, 2014 and 2013, the Company had $5.3 billion and $4.9 billion of senior notes outstanding, respectively. As of December 31, 2014, the Company did not have any outstanding secured debt. 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 and involuntary dissolution. The preferred stock and Class A preferred stock of the Company contain a feature that allows the holders to elect a majority of the Company's board of directors if preferred dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of the Company, the preferred stock and Class A preferred stock is presented as "Redeemable Preferred Stock" in a manner consistent with temporary equity under applicable accounting standards. The preference stock does not contain such a provision that would allow the holders to elect a majority of the Company's board. The Company's preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. 60 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report The Company's preferred stock is subject to redemption at a price equal to the par value plus a premium. The Company's Class A preferred stock is subject to redemption at a price equal to the stated capital. Certain series of the Company's preference stock are subject to redemption at a price equal to the stated capital plus a make-whole premium based on the present value of the liquidation amount and future dividends to the first stated capital redemption date and the other series of preference stock are subject to redemption at a price equal to the stated capital. All series of the Company's preferred stock currently are subject to redemption at the option of the Company. Information for each outstanding series is in the table below: Preferred/Preference Stock 4.92% Preferred Stock 4.72% Preferred Stock 4.64% Preferred Stock 4.60% Preferred Stock 4.52% Preferred Stock 4.20% Preferred Stock 5.83% Class A Preferred Stock 5.20% Class A Preferred Stock 5.30% Class A Preferred Stock 5.625% Preference Stock 6.450% Preference Stock 6.500% Preference Stock Par Value/ Stated Capital Per Share Shares Outstanding Redemption Price Per Share $100 $100 $100 $100 $100 $100 $25 $25 $25 $25 $25 $25 80,000 50,000 60,000 100,000 50,000 135,115 1,520,000 6,480,000 4,000,000 6,000,000 6,000,000 2,000,000 $103.23 $102.18 $103.14 $104.20 $102.93 $105.00 Stated Capital Stated Capital Stated Capital Stated Capital * * * Prior to 10/01/2017: Stated Value Plus Make-Whole Premium; after 10/01/2017: Stated Capital Dividend Restrictions The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. Assets Subject to Lien During 2014, all outstanding pollution control revenue bonds pursuant to which the Company granted liens on certain property were redeemed. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its other subsidiaries. Bank Credit Arrangements At December 31, 2014, committed credit arrangements with banks were as follows: Expires(a) 2015 2016 2018 Total $ 228 $ 50 $1,030 $1,308 (a) No credit arrangements expire in 2017. Unused (in millions) $ 1,308 Executable Term-Loans Due Within One Year One Year Two Years Term Out No Term Out $ 58 $ — $ 58 $ 170 The Company expects to renew its bank credit agreements as needed, prior to expiration. Most of the bank credit arrangements require payment of a commitment fee based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average less than 1/10 of 1% for the Company. Compensating balances are not legally restricted from withdrawal. Most of the Company's bank credit arrangements contain covenants that limit the Company's debt to 65% of total capitalization, as defined in the arrangements. For purposes of calculating these covenants, any 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, 2014, the Company was in compliance with the debt limit covenants. 61 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report A portion of the unused credit with banks is allocated to provide liquidity support to the Company's variable rate pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was $784 million as of December 31, 2014. In addition, at December 31, 2014, the Company had $280 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. The Company borrows through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. The Company may also make short-term borrowings through various other arrangements with banks. At December 31, 2014 and 2013, there was no short-term debt outstanding. At December 31, 2014, the Company had regulatory approval to have outstanding up to $2 billion of short-term borrowings. 7. COMMITMENTS Fuel and Purchased Power Agreements To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement and delivery of fossil and nuclear fuel which are not recognized on the balance sheets. In 2014, 2013, and 2012, the Company incurred fuel expense of $1.6 billion, $1.6 billion, and $1.5 billion, respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments. In addition, the Company has entered into various long-term commitments for the purchase of capacity and electricity, some of which are accounted for as operating leases. Total capacity expense under PPAs accounted for as operating leases was $37 million, $30 million, and $33 million for 2014, 2013, and 2012, respectively. Total estimated minimum long-term obligations at December 31, 2014 were as follows: 2015 2016 2017 2018 2019 2020 and thereafter Total commitments Operating Lease PPAs (in millions) $ $ 37 39 40 41 43 137 337 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. 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. Operating Leases The Company has entered into rental agreements for coal railcars, vehicles, and other equipment with various terms and expiration dates. Total rent expense was $18 million in 2014, $21 million in 2013, and $24 million in 2012. Of these amounts, $14 million, $18 million, and $19 million for 2014, 2013, and 2012, respectively, relate to the railcar leases and are recoverable through the Company's Rate ECR. As of December 31, 2014, estimated minimum lease payments under operating leases were as follows: 62 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report 2015 2016 2017 2018 2019 2020 and thereafter Total Railcars Minimum Lease Payments Vehicles & Other (in millions) Total $ $ 13 11 7 5 5 17 58 $ $ 3 3 3 1 — — 10 $ $ 16 14 10 6 5 17 68 In addition to the above rental commitments payments, the Company has potential obligations upon expiration of certain leases with respect to the residual value of the leased property. These leases have terms expiring through 2023 with maximum obligations under these leases of $5 million in 2015, $4 million in 2016, and $12 million in 2020 and thereafter. There are no obligations under these leases in 2017, 2018, and 2019. At the termination of the leases, the lessee may either 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 reduce or eliminate the Company's payments under the residual value obligations. Guarantees The Company has guaranteed the obligation of SEGCO for $25 million of pollution control revenue bonds issued in 2001, which mature in June 2019, and also $100 million of senior notes issued in November 2013, which mature in December 2018. Georgia Power has agreed to reimburse the Company for the pro rata portion of such obligations corresponding to Georgia Power's then proportionate ownership of SEGCO's stock if the Company is called upon to make such payment under its guarantee. See Note 4 for additional information. 8. STOCK COMPENSATION Stock Options Southern Company provides non-qualified stock options through its Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. As of December 31, 2014, there were approximately 1,000 current and former employees of the Company participating in the stock option program. The prices of options were at the fair market value of the shares on the dates of grant. These options 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 Omnibus Incentive Compensation Plan. Stock options held by employees of a company undergoing a change in control vest upon the change in control. For the years ended December 31, 2014, 2013, and 2012, employees of the Company were granted stock options for 2,027,298 shares, 1,319,038 shares, and 1,099,315 shares, respectively. The weighted average grant-date fair value of stock options granted during 2014, 2013, and 2012, derived using the Black-Scholes stock option pricing model, was $2.20, $2.93, and $3.39, respectively. For the years ended December 31, 2014, 2013, and 2012, total compensation cost for stock option awards recognized in income was $5 million, $4 million, and $4 million, respectively, with the related tax benefit also recognized in income of $2 million, $2 million, and $1 million, respectively. The compensation cost and tax benefits related to the grant of Southern Company stock options to the Company's employees and the exercise of stock options are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. No cash proceeds are received by the Company upon the exercise of stock options. As of December 31, 2014, there was $1 million of 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 15 months. The total intrinsic value of options exercised during the years ended December 31, 2014, 2013, and 2012 was $21 million, $11 million, and $28 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $8 million, $4 million, and $11 million for the years ended December 31, 2014, 2013, and 2012, respectively. 63 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report As of December 31, 2014, the aggregate intrinsic value for the options outstanding and options exercisable was $55 million and $37 million, respectively. Performance Shares Southern Company provides performance share award units through its Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. The performance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual months of service prior to retirement. The value of the award units is based on Southern Company's total shareholder return (TSR) over the three-year performance period which measures Southern Company's relative performance against a group of industry peers. The performance shares are delivered in common stock following the end of the performance period based on Southern Company's actual TSR and may range from 0% to 200% of the original target performance share amount. Performance share units held by employees of a company undergoing a change in control vest upon the change in control. For the years ended December 31, 2014, 2013, and 2012, employees of the Company were granted performance share units of 176,070, 141,355, and 131,820, respectively. The weighted average grant-date fair value of performance share units granted during 2014, 2013, and 2012, determined using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period, was $37.54, $40.50, and $41.99, respectively. The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. For the years ended December 31, 2014, 2013, and 2012, total compensation cost for performance share units recognized in income was $5 million annually, with the related tax benefit of $2 million annually also recognized in income. The compensation cost and tax benefits related to the grant of Southern Company performance share units 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. As of December 31, 2014, there was $5 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 20 months. 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 $13.6 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $375 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 $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 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 $255 million per incident but not more than an aggregate of $38 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 September 10, 2018. 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 $1.5 billion for members' operating nuclear generating facilities. Additionally, the Company has NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses in excess of the $1.5 billion primary coverage. On April 1, 2014, NEIL introduced a new excess non-nuclear policy providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage. 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 limits based on the projected full cost of replacement power and has elected a 12-week deductible waiting period. Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The current maximum annual assessments for the Company under the NEIL policies would be $50 million. 64 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report 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 debt trustees as may be appropriate under the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered from customers, would be borne by the Company and could have a material effect on the Company's financial condition and results of operations. All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes. 10. FAIR VALUE MEASUREMENTS Fair value measurements are 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 and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement. • Level 1 consists of observable market data in an active market for identical assets or liabilities. • Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. • 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. 65 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report As of December 31, 2014, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: As of December 31, 2014: Assets: Energy-related derivatives Nuclear decommissioning trusts:(a) Domestic equity Foreign equity U.S. Treasury and government agency securities Corporate bonds Mortgage and asset backed securities Other Cash equivalents Total Liabilities: Interest rate derivatives Energy-related derivatives Total Quoted Prices in Active Markets for Identical Assets (Level 1) Fair Value Measurements Using Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) $ — $ 403 34 — — — — 162 599 — — — $ $ $ $ $ $ (in millions) 1 83 63 34 111 18 5 — 315 8 53 61 $ $ $ $ — — — — — — 3 — 3 — — — $ $ $ $ Total 1 486 97 34 111 18 8 162 917 8 53 61 (a) Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. See Note 1 under "Nuclear Decommissioning" for additional information. 66 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: As of December 31, 2013: Assets: Energy-related derivatives Nuclear decommissioning trusts:(a) Domestic equity Foreign equity U.S. Treasury and government agency securities Corporate bonds Mortgage and asset backed securities Other Cash equivalents Total Liabilities: Energy-related derivatives Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in millions) $ — $ 392 35 — — — — 236 663 — $ $ $ $ 7 74 65 24 89 18 13 — 290 8 $ $ $ — — — — — — 3 — 3 — Total $ 7 466 100 24 89 18 16 236 956 8 $ $ (a) Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Valuation Methodologies The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the- counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally, implied volatility of interest rate options. See Note 11 for additional information on how these derivatives are used. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgment, are also obtained when available. Investments in private equity and real estate within the nuclear decommissioning trusts are generally classified as Level 3, as the underlying assets typically do not have observable inputs. The fund manager values these assets using various inputs and techniques depending on the nature of the underlying investments. The fair value of partnerships is determined by aggregating the value of the underlying assets. 67 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report As of December 31, 2014 and 2013, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: As of December 31, 2014: Nuclear decommissioning trusts: Equity – commingled funds Trust – owned life insurance Debt – commingled funds Cash equivalents: Money market funds As of December 31, 2013: Nuclear decommissioning trusts: Equity – commingled funds Trust – owned life insurance Cash equivalents: Money market funds Fair Value (in millions) Unfunded Commitments Redemption Frequency Redemption Notice Period $ $ 63 115 15 162 65 110 236 None None None None None None None Daily/Monthly Daily/7 days Daily Daily Daily 15 days 5 days Not applicable Daily/Monthly Daily/7 days Daily Daily 15 days Not applicable The nuclear decommissioning trusts include investments in TOLI. The taxable nuclear decommissioning trusts invest in the TOLI in order to minimize the impact of taxes on the portfolios and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trusts do not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. These commingled funds, along with other equity and debt commingled funds held in the nuclear decommissioning trusts, primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities may include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection. The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the Company's investment in the money market funds. As of December 31, 2014 and 2013, other financial instruments for which the carrying amount did not equal fair value were as follows: Long-term debt: 2014 2013 Carrying Amount Fair Value (in millions) $ $ 6,631 6,228 $ $ 7,321 6,534 The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates offered to the Company. 11. DERIVATIVES The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its 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 68 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report counterparty exposure and risk management practices. The Company's 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. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note 10 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Energy-Related Derivatives 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 and other various cost recovery mechanisms, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company manages fuel-hedging programs, implemented per the guidelines of the Alabama PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. To mitigate residual risks relative to movements in electricity prices, the Company may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. Energy-related derivative contracts are accounted for in one of three methods: • Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the energy cost recovery clause. • Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges which are mainly used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings. • Not Designated – 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. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. At December 31, 2014, the net volume of energy-related derivative contracts for natural gas positions for the Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows: Net Purchased mmBtu (in millions) 56 Longest Hedge Date 2017 Longest Non-Hedge Date — For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to revenue and fuel expense for the 12- month period ending December 31, 2015 are immaterial. Interest Rate Derivatives The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to earnings. 69 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report At December 31, 2014, the following interest rate derivatives were outstanding: Interest Rate Received Weighted Average Interest Rate Paid Hedge Maturity Date Notional Amount (in millions) Fair Value Gain (Loss) December 31, 2014 (in millions) Cash Flow Hedges of Forecasted Debt $200 3-month LIBOR 2.93% October 2025 $ (8) The estimated pre-tax losses that will be reclassified from accumulated OCI to interest expense for the 12-month period ending December 31, 2015 are $3 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2035. Derivative Financial Statement Presentation and Amounts At December 31, 2014 and 2013, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: Derivative Category Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Total derivatives designated as hedging instruments for regulatory purposes Derivatives designated as hedging instruments in cash flow hedges Interest rate derivatives: Total Asset Derivatives Liability Derivatives Balance Sheet Location 2014 2013 (in millions) Balance Sheet Location 2014 2013 (in millions) Other current assets $ Other deferred charges and assets 1 — $ 1 $ $ 5 2 7 Other current liabilities Other deferred credits and liabilities $ 32 21 $ 53 $ $ 3 5 8 Other current assets $ — 1 $ $ — $ 7 Other current liabilities $ $ 8 61 $ — $ 8 Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2014 and 2013. 70 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report The derivative contracts of the Company are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related and interest rate derivative contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts at December 31, 2014 and 2013 are presented in the following tables. Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure table below. Assets 2014 2013 Liabilities Fair Value Energy-related derivatives presented in the Balance Sheet (a) Gross amounts not offset in the Balance Sheet (b) Net energy-related derivative assets (in millions) $ 1 $ 7 — (5) Energy-related derivatives presented in the Balance Sheet (a) Gross amounts not offset in the Balance Sheet (b) 2014 2013 (in millions) $ 53 $ 8 — (5) $ 1 $ 2 Net energy-related derivative liabilities $ 53 $ 3 (a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. (b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. At December 31, 2014 and 2013, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets was as follows: Derivative Category Energy-related derivatives: Total energy-related derivative gains (losses) Unrealized Losses Unrealized Gains Balance Sheet Location Other regulatory assets, current Other regulatory assets, deferred Balance Sheet Location Other current liabilities Other regulatory liabilities, deferred 2014 2013 (in millions) $ (32) $ (3) (21) (5) $ (53) $ (8) 2014 2013 (in millions) $ 1 — $ 1 $ $ 5 2 7 For the years ended December 31, 2014, 2013, and 2012, the pre-tax effect of interest rate derivatives designated as cash flow hedging instruments on the statements of income was as follows: Derivatives in Cash Flow Hedging Relationships Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Derivative Category 2014 2013 (in millions) Statements of Income Location 2012 2014 Amount 2013 (in millions) 2012 Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) Interest rate derivatives $ (8) $ — $ (18) Interest expense, net of amounts capitalized $ (3) $ (3) $ (3) There was no material ineffectiveness recorded in earnings for any period presented. For the years ended December 31, 2014, 2013, and 2012, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income was not material. Contingent Features 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 derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2014, the Company's collateral posted with its derivative counterparties was not material. At December 31, 2014, the fair value of derivative liabilities with contingent features was $18 million. However, because of joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the 71 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $54 million, and include certain agreements that could require collateral in the event that one or more Southern Company system 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. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty. The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. 72 NOTES TO FINANCIAL STATEMENTS (continued) Alabama Power Company 2014 Annual Report 12. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Summarized quarterly financial information for 2014 and 2013 is as follows: Quarter Ended March 2014 June 2014 September 2014 December 2014 March 2013 June 2013 September 2013 December 2013 Operating Revenues Operating Income Net Income After Dividends on Preferred and Preference Stock $ $ 1,508 1,437 1,669 1,328 1,308 1,392 1,604 1,314 $ $ (in millions) 381 357 520 267 307 357 500 312 $ $ 187 173 282 119 141 173 258 140 The Company's business is influenced by seasonal weather conditions. 73 SELECTED FINANCIAL AND OPERATING DATA 2010-2014 Alabama Power Company 2014 Annual Report $ $ $ $ Operating Revenues (in millions) Net Income After Dividends on Preferred and Preference Stock (in millions) $ Cash Dividends on Common Stock (in millions) $ Return on Average Common Equity (percent) Total Assets (in millions) Gross Property Additions (in millions) Capitalization (in millions): Common stock equity Preference stock Redeemable preferred stock Long-term debt Total (excluding amounts due within one year) Capitalization Ratios (percent): Common stock equity Preference stock Redeemable preferred stock Long-term debt Total (excluding amounts due within one year) Customers (year-end): Residential Commercial Industrial Other Total Employees (year-end) $ $ $ $ $ $ $ $ 2014 5,942 761 550 13.52 20,552 1,543 5,752 343 342 6,176 12,613 45.6 2.7 2.7 49.0 100.0 $ $ $ $ $ $ $ 2013 5,618 712 644 13.07 19,251 1,204 5,502 343 342 6,233 12,420 44.3 2.8 2.7 50.2 100.0 $ $ $ $ $ $ $ 2012 5,520 704 684 13.10 18,712 940 5,398 343 342 5,929 12,012 44.9 2.9 2.8 49.4 100.0 $ $ $ $ $ $ $ 2011 5,702 708 774 13.19 18,477 1,016 5,342 343 342 5,632 11,659 45.8 2.9 2.9 48.4 100.0 2010 5,976 707 586 13.31 17,994 956 5,393 343 342 5,987 12,065 44.7 2.9 2.8 49.6 100.0 1,247,061 197,082 6,032 753 1,450,928 6,935 1,241,998 196,209 5,851 751 1,444,809 6,896 1,237,730 196,177 5,839 748 1,440,494 6,778 1,231,574 196,270 5,844 746 1,434,434 6,632 1,235,128 197,336 5,770 782 1,439,016 6,552 74 SELECTED FINANCIAL AND OPERATING DATA 2010-2014 (continued) Alabama Power Company 2014 Annual Report Operating Revenues (in millions): Residential Commercial Industrial Other Total retail Wholesale — non-affiliates Wholesale — affiliates Total revenues from sales of electricity Other revenues Total Kilowatt-Hour Sales (in millions): Residential Commercial Industrial Other Total retail Wholesale — non-affiliates Wholesale — 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 $ $ $ $ 2014 2,209 1,533 1,480 27 5,249 281 189 5,719 223 5,942 18,726 14,118 23,799 211 56,854 3,588 6,713 67,155 11.80 10.86 6.22 9.23 4.56 8.52 2013 2012 2011 2010 $ $ 2,079 1,477 1,369 27 4,952 248 212 5,412 206 5,618 17,920 13,892 22,904 211 54,927 3,711 7,672 66,310 11.60 10.63 5.98 9.02 4.04 8.16 $ $ 2,068 1,491 1,346 28 4,933 277 111 5,321 199 5,520 17,612 13,963 22,158 214 53,947 4,196 4,279 62,422 11.74 10.68 6.07 9.14 4.58 8.52 $ $ 2,144 1,495 1,306 27 4,972 287 244 5,503 199 5,702 18,650 14,173 21,666 214 54,703 4,330 7,211 66,244 11.50 10.55 6.03 9.09 4.60 8.31 2,283 1,535 1,231 27 5,076 465 236 5,777 199 5,976 20,417 14,719 20,622 216 55,974 8,655 6,074 70,703 11.18 10.43 5.97 9.07 4.76 8.17 15,051 14,451 14,252 15,138 16,570 $ 1,775 $ 1,676 $ 1,674 $ 1,740 $ 1,853 12,222 12,222 12,222 12,222 12,222 11,761 11,054 61.4 82.5 93.3 49.0 20.7 5.5 15.4 3.6 5.8 100.0 9,347 10,692 64.9 87.3 90.7 50.0 20.3 8.1 15.7 2.9 3.0 100.0 10,285 11,096 61.3 88.6 94.5 48.2 22.6 4.1 16.8 2.0 6.3 100.0 11,553 11,500 60.6 88.7 94.7 52.5 20.8 4.6 15.3 0.9 5.9 100.0 11,349 11,488 62.6 92.9 88.4 56.6 17.7 5.0 14.0 1.6 5.1 100.0 * Beginning in 2012, plant availability is calculated as a weighted equivalent availability. 75 (cid:3) DIRECTORS(cid:3)AND(cid:3)OFFICERS(cid:3) Alabama Power Company 2014 Annual Report Directors Whit Armstrong Managing Member, Creeke Capital Investments, LLC Ralph D. Cook City Attorney, City of Birmingham David J. Cooper, Sr. Vice Chairman, Cooper/T. Smith Corporation Mark A. Crosswhite1 Chairman, President, and Chief Executive Officer, Alabama Power Company Thomas A. Fanning2 Chairman, President, and CEO, The Southern Company John D. Johns2 Chairman, President, and CEO, Protective Life Corporation Anthony A. Joseph3 Shareholder, Maynard, Cooper & Gale, P.C. Patricia M. King President, Sunny King Automotive Group James K. Lowder Chairman, The Colonial Company Charles D. McCrary4 Chairman, Alabama Power Company Malcolm Portera Partner, Portera and Associates Robert D. Powers President, The Eufaula Agency, Inc. Catherine J. Randall3 Chairman, Pettus Randall Holdings, LLC C. Dowd Ritter Retired Chairman and CEO, Regions Financial Corporation James H. Sanford Chairman, HOME Place Farms, Inc. John Cox Webb, IV5 President, Webb Lumber Company, Inc. Officers Mark A. Crosswhite1 Chairman, President, and Chief Executive Officer Philip C. Raymond Executive Vice President, Chief Financial Officer, and Treasurer Zeke W. Smith Executive Vice President Steven R. Spencer Executive Vice President James P. Heilbron Senior Vice President and Senior Production Officer Gordon G. Martin Senior Vice President and General Counsel Gregory J. Barker Senior Vice President Anita Allcorn-Walker Vice President and Comptroller Ronald Q. Patterson Vice President and Assistant Treasurer Matthew W. Bowden Vice President C. David Cox Vice President Mark S. Crews Vice President Daniel K. Glover Vice President R. Myrk Harkins Vice President John O. Hudson III Vice President Richard O. Hutto Vice President Stacy R. Kilcoyne Vice President Barbara J. Knight Vice President 76 R. Scott Moore Vice President Kenneth F. Novak Vice President Jonathan K. Porter Vice President Quentin P. Riggins Vice President Leslie L. Sanders Vice President R. Michael Saxon Vice President Don A. Scivley Vice President Julia H. Segars Vice President Nicholas C. Sellers Vice President Anthony A. Smoke6 Vice President Robert L. Weaver Vice President Ceila H. Shorts Corporate Secretary Wendy M. Hoomes Assistant Comptroller Melissa K. Caen Assistant Secretary and Assistant Treasurer Amy E. Blankenship Assistant Secretary Christopher R. Blake Assistant Treasurer Brian E. George7 Assistant Treasurer (cid:3) 1 Elected Chairman effective 5/2014 2 Resigned effective 2/2015 3 Elected effective 1/2015 4 Retired effective 5/2014 5 Retiring effective 4/2015 6 Elected effective 5/2014 7 Appointed effective 12/2014 Number of Preferred Shareholders of record as of December 31, 2014 was 1,058. 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- 2619. Alabama Power Company 600 North 18th Street Birmingham, AL 35203 (205) 257-1000 www.alabamapower.com Auditors Deloitte & Touche LLP 420 North 20th Street Suite 2400 Birmingham, AL 35203 Legal Counsel Balch & Bingham LLP P.O. Box 306 Birmingham, AL 35201 (cid:3) CORPORATE INFORMATION Alabama Power Company 2014 Annual Report General This annual report is submitted for general information and is not intended for use in connection with any sale or purchase of, or any solicitation of offers to buy or sell securities. Profile The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast. The Company sells electricity to more than 1.4 million customers within its service area of approximately 45,000 square miles. In 2014, retail energy sales accounted for 85 percent of the Company’s total sales of 67 billion kilowatt-hours. 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. Trustee, Registrar, and 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 of Preferred and Preference Stock Computershare Inc. P.O. Box 30170 College Station, TX 77842-3170 (800) 554-7626 www.computershare.com/investor 77 (cid:62)(cid:55)(cid:75)(cid:76)(cid:86)(cid:3)(cid:83)(cid:68)(cid:74)(cid:72)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:81)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:79)(cid:92)(cid:3)(cid:79)(cid:72)(cid:73)(cid:87)(cid:3)(cid:69)(cid:79)(cid:68)(cid:81)(cid:78)(cid:64) (cid:62)(cid:55)(cid:75)(cid:76)(cid:86)(cid:3)(cid:83)(cid:68)(cid:74)(cid:72)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:81)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:79)(cid:92)(cid:3)(cid:79)(cid:72)(cid:73)(cid:87)(cid:3)(cid:69)(cid:79)(cid:68)(cid:81)(cid:78)(cid:64) (cid:62)(cid:55)(cid:75)(cid:76)(cid:86)(cid:3)(cid:83)(cid:68)(cid:74)(cid:72)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:81)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:79)(cid:92)(cid:3)(cid:79)(cid:72)(cid:73)(cid:87)(cid:3)(cid:69)(cid:79)(cid:68)(cid:81)(cid:78)(cid:64)

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