Item 1. BUSINESS
Southern Company was incorporated under the laws of Delaware on November 9, 1945. Southern Company is domesticated under the laws of Georgia and is qualified to do business as a foreign corporation under the laws of Alabama. Southern Company owns all of the outstanding common stock of Alabama Power, Georgia Power, Gulf Power, and Mississippi Power, each of which is an operating public utility company. The traditional operating companies supply electric service in the states of Alabama, Georgia, Florida, and Mississippi. More particular information relating to each of the traditional operating companies is as follows:
Alabama Power is a corporation organized under the laws of the State of Alabama on November 10, 1927, by the consolidation of a predecessor Alabama Power Company, Gulf Electric Company, and Houston Power Company. The predecessor Alabama Power Company had been in continuous existence since its incorporation in 1906.
Georgia Power was incorporated under the laws of the State of Georgia on June 26, 1930, and admitted to do business in Alabama on September 15, 1948. Effective July 1, 2006, Savannah Electric, formerly a wholly-owned subsidiary of Southern Company, was merged with and into Georgia Power.
Gulf Power is a Florida corporation that has had a continuous existence since it was originally organized under the laws of the State of Maine on November 2, 1925. Gulf Power was admitted to do business in Florida on January 15, 1926, in Mississippi on October 25, 1976, and in Georgia on November 20, 1984. Gulf Power became a Florida corporation after being domesticated under the laws of the State of Florida on November 2, 2005.
Mississippi Power was incorporated under the laws of the State of Mississippi on July 12, 1972, was admitted to do business in Alabama on November 28, 1972, and effective December 21, 1972, by the merger into it of the predecessor Mississippi Power Company, succeeded to the business and properties of the latter company. The predecessor Mississippi Power Company was incorporated under the laws of the State of Maine on November 24, 1924, and was admitted to do business in Mississippi on December 23, 1924, and in Alabama on December 7, 1962.
In addition, Southern Company owns all of the common stock of Southern Power, which is also an operating public utility company. Southern Power constructs, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. Southern Power is a corporation organized under the laws of Delaware on January 8, 2001 and was admitted to do business in the States of Alabama, Florida, and Georgia on January 10, 2001, in the State of Mississippi on January 30, 2001, and in the State of North Carolina on February 19, 2007.
Southern Company also owns all the outstanding common stock or membership interests of SouthernLINC Wireless, Southern Nuclear, SCS, Southern Holdings and other direct and indirect subsidiaries. SouthernLINC Wireless provides digital wireless communications services to the traditional operating companies and markets these services to the public and also provides wholesale fiber optic solutions to telecommunication providers in the Southeast. Southern Nuclear operates and provides services to Alabama Power’s and Georgia Power’s nuclear plants. SCS is the system service company providing, at cost, specialized services to Southern Company and its subsidiary companies. Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy-related businesses. The investments in synthetic fuels ended on December 31, 2007.
Alabama Power and Georgia Power each own 50% of the outstanding common stock of SEGCO. SEGCO is an operating public utility company that owns electric generating units with an aggregate capacity of 1,019,680 kilowatts at Plant Gaston on the Coosa River near Wilsonville, Alabama. Alabama Power and Georgia Power are each entitled to one-half of SEGCO’s capacity and energy. Alabama Power acts as SEGCO’s agent in the operation of SEGCO’s units and furnishes coal to SEGCO as fuel for its units. SEGCO also owns three 230,000 volt transmission lines extending from Plant Gaston to the Georgia state line at which point connection is made with the Georgia Power
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transmission line system.
Southern Company’s segments and related information is included in Note 10 to the financial statements of Southern Company in Item 8 herein.
The registrants’ Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports are made available on Southern Company’s website, free of charge, as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. Southern Company’s internet address is www.southerncompany.com.
The Southern Company System
Traditional Operating Companies
The traditional operating companies own generation and transmission facilities. See PROPERTIES in Item 2 herein for additional information on the traditional operating companies’ generating facilities. The transmission facilities of each of the traditional operating companies are connected to the respective company’s own generating plants and other sources of power and are interconnected with the transmission facilities of the other traditional operating companies and SEGCO by means of heavy-duty high voltage lines. For information on Georgia Power’s integrated transmission system, see “Territory Served by the Traditional Operating Companies and Southern Power” herein.
Operating contracts covering arrangements in effect with principal neighboring utility systems provide for capacity exchanges, capacity purchases and sales, transfers of economy energy, and other similar transactions. Additionally, the traditional operating companies have entered into voluntary reliability agreements with the subsidiaries of Entergy Corporation, Florida Electric Power Coordinating Group and TVA and with Progress Energy Carolinas, Duke Energy, South Carolina Electric & Gas Company, and Virginia Electric and Power Company, each of which provides for the establishment and periodic review of principles and procedures for planning and operation of generation and transmission facilities, maintenance schedules, load retention programs, emergency operations, and other matters affecting the reliability of bulk power supply. The traditional operating companies have joined with other utilities in the Southeast (including those referred to above) to form the SERC to augment further the reliability and adequacy of bulk power supply. Through the SERC, the traditional operating companies are represented on the National Electric Reliability Council.
The IIC provides for coordinating operations of the power producing facilities of the traditional operating companies and Southern Power and the capacities available to such companies from non-affiliated sources and for the pooling of surplus energy available for interchange. Coordinated operation of the entire interconnected system is conducted through a central power supply coordination office maintained by SCS. The available sources of energy are allocated to the traditional operating companies and Southern Power to provide the most economical sources of power consistent with reliable operation. The resulting benefits and savings are apportioned among each of the companies. See MANAGEMENT’S DISCUSSION AND ANALYSIS - FUTURE EARNINGS POTENTIAL - “FERC Matters - Intercompany Interchange Contract” of each registrant in Item 7 herein and Note 3 to the financial statements of each registrant, all under “FERC Matters - Intercompany Interchange Contract” in Item 8 herein for information on the settlement of the FERC proceeding related to the IIC.
Southern Company, each traditional operating company, Southern Power, Southern Nuclear, SEGCO, and other subsidiaries have contracted with SCS to furnish, at direct or allocated cost and upon request, the following services: general and design engineering, purchasing, accounting and statistical analysis, finance and treasury, tax, information resources, marketing, auditing, insurance and pension administration, human resources, systems and procedures, and other services with respect to business and operations and power pool transactions. Southern Power and SouthernLINC Wireless have also secured from the traditional operating companies certain services which are furnished at cost and, in the case of Southern Power in compliance with FERC regulations.
Alabama Power and Georgia Power each have a contract with Southern Nuclear to operate Plant Farley and Plants Hatch and Vogtle, respectively. See “Regulation - Nuclear Regulation” herein for additional information.
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Southern Power
Southern Power is an electric wholesale generation subsidiary with market-based rate authority from the FERC. Southern Power constructs, acquires, owns, and manages generating facilities and sells the output under long-term, fixed-price capacity contracts both to unaffiliated wholesale purchasers as well as to the traditional operating companies (under PPAs approved by the applicable state PSCs and the FERC). Southern Power’s business activities are not subject to traditional state regulation of utilities but are subject to regulation by the FERC. Southern Power has attempted to insulate itself from significant fuel supply, fuel transportation, and electric transmission risks by making such risks the responsibility of the counterparties to the PPAs. However, Southern Power’s overall profit will depend on the parameters of the wholesale market and the efficient operation of its wholesale generating assets. For additional information on Southern Power’s business activities, see MANAGEMENT’S DISCUSSION AND ANALYSIS- OVERVIEW- “Business Activities” of Southern Power in Item 7 herein.
In 2006, Southern Power acquired all of the outstanding membership interests of DeSoto County Generating Company, LLC and Rowan County Power, LLC from a subsidiary of Progress Energy, Inc. For additional information on these acquisitions see Note 2 to the financial statements of Southern Power in Item 8 herein. At December 31, 2007, Southern Power had 6,896 megawatts of nameplate capacity in commercial operation.
Other Businesses
Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy-related businesses. Southern Company’s interest in one of the synthetic fuel entities was terminated in 2006. Synthetic fuel tax credits expired on December 31, 2007 and the synthetic fuel investments were terminated on December 31, 2007.
SouthernLINC Wireless serves the traditional operating companies and markets its services to non-affiliates within the Southeast. SouthernLINC Wireless delivers multiple wireless communication options including push to talk, cellular service, text messaging, wireless internet access, and wireless data. Its system covers approximately 128,000 square miles in the Southeast. SouthernLINC Wireless also provides wholesale fiber optic solutions to telecommunication providers in the Southeast.
These efforts to invest in and develop new business opportunities offer potential returns exceeding those of rate-regulated operations. However, these activities also involve a higher degree of risk.
Construction Programs
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. For estimated construction and environmental expenditures for the periods 2008 through 2010, see Note 7 to the financial statements of each registrant all under “Construction Program” in Item 8 herein. Estimated construction costs in 2008 are expected to be apportioned approximately as follows: (in millions)
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*
These amounts include the traditional operating companies and Southern Power (as detailed in the table above) as well as the amounts for the other subsidiaries. See “Other Businesses” herein for additional information.
The construction programs are subject to periodic review and revision, and actual construction costs may vary materially from the above estimates because of numerous factors. These factors include: changes in business conditions; acquisition of additional generating assets; revised load growth estimates; changes in environmental statutes and regulations; changes in existing nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; increasing costs of labor, equipment and materials; cost of capital and other factors described above under the heading “Cautionary Notice Regarding Forward Looking Statements.” In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Under Georgia law, Georgia Power is required to file an IRP for approval by the Georgia PSC. Through the IRP process, the Georgia PSC must pre-certify the construction of new power plants and new PPAs. See “Rate Matters - Integrated Resource Planning” herein for additional information.
See “Regulation - Environmental Statutes and Regulations” herein for additional information with respect to certain existing and proposed environmental requirements and PROPERTIES - “Jointly-Owned Facilities” in Item 2 herein for additional information concerning Alabama Power’s, Georgia Power’s, and Southern Power’s joint ownership of certain generating units and related facilities with certain non-affiliated utilities.
Financing Programs
See each of the registrant’s MANAGEMENT’S DISCUSSION AND ANALYSIS - FINANCIAL CONDITION AND LIQUIDITY in Item 7 herein and Note 6 to the financial statements of each registrant in Item 8 herein for information concerning financing programs.
Fuel Supply
The traditional operating companies’ and SEGCO’s supply of electricity is derived predominantly from coal. Southern Power’s supply of electricity is primarily fueled by natural gas. See MANAGEMENT’S DISCUSSION AND ANALYSIS - RESULTS OF OPERATION - “Fuel and Purchased Power Expenses” of Southern Company and each traditional operating company in Item 7 herein for information regarding the electricity generated and the average cost of fuel in cents per net kilowatt-hour generated for the years 2005 through 2007.
The traditional operating companies have agreements in place from which they expect to receive approximately 84% of their coal burn requirements in 2008. These agreements have terms ranging between one and seven years. In 2007, the weighted average sulfur content of all coal burned by the traditional operating companies was 0.84% sulfur. This sulfur level, along with banked and purchased sulfur dioxide allowances, allowed the traditional operating companies to remain within limits set by the Phase II acid rain requirements of the Clean Air Act. In 2007, Southern Company purchased approximately $50.76 million of sulfur dioxide and nitrogen oxide emission allowances to be used in current and future periods. As additional environmental regulations are proposed that impact the utilization of coal, the traditional operating companies’ fuel mix will be monitored to ensure that the traditional operating companies remain in compliance with applicable laws and regulations. Additionally, Southern Company and the traditional operating companies will continue to evaluate the need to purchase additional emission allowances and the timing of capital expenditures for emission control equipment. See MANAGEMENT’S DISCUSSION AND ANALYSIS - FUTURE EARNINGS POTENTIAL - “Environmental Matters” of Southern Company and each traditional operating company in Item 7 herein for information on the Clean Air Act and global climate issues.
SCS, acting on behalf of the traditional operating companies and Southern Power, has agreements in place for the natural gas burn requirements of the Southern Company system. For 2008, SCS has contracted for 650 billion cubic feet of natural gas supply. These agreements cover remaining terms up to 12 years. In addition to gas supply, SCS has contracts in place for both firm gas transportation and storage. Management believes that these contracts provide sufficient natural gas supplies, transportation, and storage to ensure normal operations of the Southern Company system’s natural gas generating units.
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Changes in fuel prices to the traditional operating companies are generally reflected in fuel adjustment clauses contained in rate schedules. See “Rate Matters - Rate Structure and Cost Recovery Plans” herein for additional information. Southern Power’s PPAs generally provide that the counterparty is responsible for substantially all of the cost of fuel.
Alabama Power and Georgia Power have numerous contracts covering a portion of their nuclear fuel needs for uranium, conversion services, enrichment services and fuel fabrication. These contracts have varying expiration dates and most of them are for less than 10 years. Management believes that sufficient capacity for nuclear fuel supplies and processing exists to preclude the impairment of normal operations of the Southern Company system’s nuclear generating units.
Alabama Power and Georgia Power have contracts with the United States, acting through the DOE, that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent fuel in 1998, as required by the contracts, and Alabama Power and Georgia Power are pursuing legal remedies against the government for breach of contract. See Note 1 to the financial statements of Southern Company, Alabama Power, and Georgia Power under “Nuclear Fuel Disposal Costs” in Item 8 herein for additional information.
Territory Served by the Traditional Operating Companies and Southern Power
The territory in which the traditional operating companies provide electric service comprises most of the states of Alabama and Georgia together with the northwestern portion of Florida and southeastern Mississippi. In this territory there are non-affiliated electric distribution systems which obtain some or all of their power requirements either directly or indirectly from the traditional operating companies. The territory has an area of approximately 120,000 square miles and an estimated population of approximately 13 million. Southern Power sells electricity at market-based prices in the Super-Southeast wholesale market to investor-owned utilities, IPPs, municipalities, and electric cooperatives.
Alabama Power is engaged, within the State of Alabama, in the generation and purchase of electricity and the transmission, distribution, and sale of such electricity at retail in over 650 communities (including Anniston, Birmingham, Gadsden, Mobile, Montgomery, and Tuscaloosa) and at wholesale to 15 municipally-owned electric distribution systems, 11 of which are served indirectly through sales to AMEA, and two rural distributing cooperative associations. Alabama Power also supplies steam service in downtown Birmingham. Alabama Power owns coal reserves near its Plant Gorgas and uses the output of coal from the reserves in its generating plants. Alabama Power also sells, and cooperates with dealers in promoting the sale of, electric appliances.
Georgia Power is engaged in the generation and purchase of electricity and the transmission, distribution, and sale of such electricity within the State of Georgia at retail in over 600 communities (including Athens, Atlanta, Augusta, Columbus, Macon, Rome, and Savannah), as well as in rural areas, and at wholesale currently to OPC, MEAG, Dalton, Hampton, and 30 electric cooperatives.
Gulf Power is engaged, within the northwestern portion of Florida, in the generation and purchase of electricity and the transmission, distribution, and sale of such electricity at retail in 71 communities (including Pensacola, Panama City, and Fort Walton Beach), as well as in rural areas, and at wholesale to a non-affiliated utility and a municipality.
Mississippi Power is engaged in the generation and purchase of electricity and the transmission, distribution, and sale of such energy within 23 counties in southeastern Mississippi, at retail in 123 communities (including Biloxi, Gulfport, Hattiesburg, Laurel, Meridian, and Pascagoula), as well as in rural areas, and at wholesale to one municipality, six rural electric distribution cooperative associations, and one generating and transmitting cooperative.
For information relating to kilowatt-hour sales by classification for the traditional operating companies, see MANAGEMENT’S DISCUSSION AND ANALYSIS - RESULTS OF OPERATIONS of each traditional operating company in Item 7 herein. Also, for information relating to the sources of revenues for Southern Company, each traditional operating company, and Southern Power, reference is made to Item 6 herein.
The RUS has authority to make loans to cooperative associations or corporations to enable them to provide electric
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service to customers in rural sections of the country. There are 71 electric cooperative organizations operating in the territory in which the traditional operating companies provide electric service at retail or wholesale.
One of these organizations, PowerSouth, is a generating and transmitting cooperative selling power to several distributing cooperatives, municipal systems, and other customers in south Alabama and northwest Florida. PowerSouth owns generating units with approximately 1,776 megawatts of nameplate capacity, including an undivided 8.16% ownership interest in Alabama Power’s Plant Miller Units 1 and 2. PowerSouth’s facilities were financed with RUS loans secured by long-term contracts requiring distributing cooperatives to take their requirements from PowerSouth to the extent such energy is available.
Alabama Power and Gulf Power have entered into separate agreements with PowerSouth involving interconnection between their respective systems. The delivery of capacity and energy from PowerSouth to certain distributing cooperatives in the service areas of Alabama Power and Gulf Power is governed by the Southern Company/PowerSouth Network Transmission Service Agreement. The rates for this service to PowerSouth are on file with the FERC. See PROPERTIES - “Jointly-Owned Facilities” in Item 2 herein for details of Alabama Power’s joint-ownership with PowerSouth of a portion of Plant Miller.
Four electric cooperative associations, financed by the RUS, operate within Gulf Power’s service area. These cooperatives purchase their full requirements from PowerSouth and SEPA (a federal power marketing agency). A non-affiliated utility also operates within Gulf Power’s service area and purchases its full requirements from Gulf Power.
Mississippi Power has an interchange agreement with SMEPA, a generating and transmitting cooperative, pursuant to which various services are provided, including the furnishing of protective capacity by Mississippi Power to SMEPA.
There are also 65 municipally-owned electric distribution systems operating in the territory in which the traditional operating companies provide electric service at retail or wholesale.
Forty-eight municipally-owned electric distribution systems and one county-owned system receive their requirements through MEAG, which was established by a Georgia state statute in 1975. MEAG serves these requirements from self-owned generation facilities, some of which are acquired and jointly-owned with Georgia Power, power purchased from Georgia Power, and purchases from other resources. MEAG also has a pseudo scheduling and services agreement with Georgia Power. Dalton serves its requirements from self-owned generation facilities, some of which are acquired and jointly-owned with Georgia Power, and through purchases from Georgia Power pursuant to their partial requirements tariff. In addition, Georgia Power serves the full requirements of Hampton’s electric distribution system under a market-based contract. See PROPERTIES - “Jointly-Owned Facilities” in Item 2 herein for additional information.
Georgia Power has entered into substantially similar agreements with Georgia Transmission Corporation (formerly OPC’s transmission division), MEAG, and Dalton providing for the establishment of an integrated transmission system to carry the power and energy of all parties. The agreements require an investment by each party in the integrated transmission system in proportion to its respective share of the aggregate system load. See PROPERTIES - “Jointly-Owned Facilities” in Item 2 herein for additional information.
Southern Power has PPAs with the municipalities of Dalton, North Carolina Municipal Power Agency No. 1, Florida Municipal Power Agency, and Piedmont Municipal Power Agency. See MANAGEMENT’S DISCUSSION AND ANALYSIS - FUTURE EARNINGS POTENTIAL - “Power Sales Agreements” of Southern Power in Item 7 herein for additional information concerning Southern Power’s PPAs.
SCS, acting on behalf of the traditional operating companies, also has a contract with SEPA providing for the use of the traditional operating companies’ facilities at government expense to deliver to certain cooperatives and municipalities, entitled by federal statute to preference in the purchase of power from SEPA, quantities of power equivalent to the amounts of power allocated to them by SEPA from certain United States government hydroelectric projects.
The retail service rights of all electric suppliers in the State of Georgia are regulated by the Territorial Electric
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Service Act of 1973. Pursuant to the provisions of this Act, all areas within existing municipal limits were assigned to the primary electric supplier therein. Areas outside of such municipal limits were either to be assigned or to be declared open for customer choice of supplier by action of the Georgia PSC pursuant to standards set forth in this Act. Consistent with such standards, the Georgia PSC has assigned substantially all of the land area in the state to a supplier. Notwithstanding such assignments, this Act provides that any new customer locating outside of 1973 municipal limits and having a connected load of at least 900 kilowatts may exercise a one-time choice for the life of the premises to receive electric service from the supplier of its choice. See “Competition” herein for additional information.
Pursuant to the 1956 Utility Act, the Mississippi PSC issued “Grandfather Certificates” of public convenience and necessity to Mississippi Power and to six distribution rural cooperatives operating in southeastern Mississippi, then served in whole or in part by Mississippi Power, authorizing them to distribute electricity in certain specified geographically described areas of the state. The six cooperatives serve approximately 325,000 retail customers in a certificated area of approximately 10,300 square miles. In areas included in a “Grandfather Certificate,” the utility holding such certificate may, without further certification, extend its lines up to five miles; other extensions within that area by such utility, or by other utilities, may not be made except upon a showing of, and a grant of a certificate of, public convenience and necessity. Areas included in such a certificate which are subsequently annexed to municipalities may continue to be served by the holder of the certificate, irrespective of whether it has a franchise in the annexing municipality. On the other hand, the holder of the municipal franchise may not extend service into such newly annexed area without authorization by the Mississippi PSC.
Competition
The electric utility industry in the United States is continuing to evolve as a result of regulatory and competitive factors. Among the early primary agents of change was the Energy Act of 1992 which allowed IPPs to access a utility’s transmission network in order to sell electricity to other utilities.
The competition for retail energy sales among competing suppliers of energy is influenced by various factors, including price, availability, technological advancements, service, and reliability. These factors are, in turn, affected by, among other influences, regulatory, political, and environmental considerations, taxation, and supply.
Generally, the traditional operating companies have experienced, and expect to continue to experience, competition in their respective retail service territories in varying degrees as the result of self-generation (as described above) by customers and other factors. See also “Territory Served by the Traditional Operating Companies and Southern Power” herein for additional information concerning suppliers of electricity operating within or near the areas served at retail by the traditional operating companies.
Southern Power competes with investor owned utilities, IPPs, and others for wholesale energy sales in primarily the Southeastern United States wholesale market. The needs of this market are driven by the demands of end users in the Southeast and the generation available. Southern Power’s success in wholesale energy sales is influenced by various factors including reliability and availability of Southern Power’s plants, availability of transmission to serve the demand, price, and Southern Power’s ability to contain costs.
Alabama Power currently has cogeneration contracts in effect with 10 industrial customers. Under the terms of these contracts, Alabama Power purchases excess generation of such companies. During 2007, Alabama Power purchased approximately 101 million kilowatt-hours from such companies at a cost of $4.9 million.
Georgia Power currently has contracts in effect with nine small power producers whereby Georgia Power purchases their excess generation. During 2007, Georgia Power purchased 8 million kilowatt-hours from such companies at a cost of $0.6 million. Georgia Power has PPAs for electricity with two cogeneration facilities. Payments are subject to reductions for failure to meet minimum capacity output. During 2007, Georgia Power purchased 559 million kilowatt-hours at a cost of $86.9 million from these facilities.
Also during 2007, Georgia Power purchased energy from seven customer-owned generating facilities. Six of the seven customers provide only energy to Georgia Power. These six customers make no capacity commitment and are not dispatched by Georgia Power. Georgia Power does have a contract with the remaining customer for eight
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megawatts of dispatchable capacity and energy. During 2007, Georgia Power purchased a total of 88 million kilowatt-hours from the seven suppliers at a cost of approximately $2.8 million.
Gulf Power currently has agreements in effect with various industrial, commercial, and qualifying facilities pursuant to which Gulf Power purchases “as available” energy from customer-owned generation. During 2007, Gulf Power purchased 57.8 million kilowatt-hours from such companies for approximately $2.3 million.
Mississippi Power currently has a cogeneration agreement in effect with one of its industrial customers. Under the terms of this contract, Mississippi Power purchases any excess generation. During 2007, this customer had no excess generation.
Seasonality
The demand for electric power generation is affected by seasonal differences in the weather. At the traditional operating companies and Southern Power, the demand for power peaks during the summer months, with market prices reflecting the demand of power and available generating resources at that time. Power demand peaks can also be recorded during the winter. As a result, the overall operating results of Southern Company, the traditional operating companies, and Southern Power in the future may fluctuate substantially on a seasonal basis. In addition, Southern Company, the traditional operating companies, and Southern Power have historically sold less power when weather conditions are milder.
Regulation
State Commissions
The traditional operating companies are subject to the jurisdiction of their respective state PSCs. The PSCs have broad powers of supervision and regulation over public utilities operating in the respective states, including their rates, service regulations, sales of securities (except for the Mississippi PSC), and, in the cases of the Georgia PSC and the Mississippi PSC, in part, retail service territories. See “Territory Served by the Traditional Operating Companies and Southern Power” and “Rate Matters” herein for additional information.
Federal Power Act
In 2005, the U.S. Congress passed the Energy Act of 2005 which repealed the Holding Company Act effective February 8, 2006. The traditional operating companies, Southern Power and its generation subsidiaries, and SEGCO are all public utilities engaged in wholesale sales of energy in interstate commerce and therefore remain subject to the rate, financial, and accounting jurisdiction of the FERC under the Federal Power Act. The FERC must approve certain financings and allows an “at cost standard” for services rendered by system service companies such as SCS. In addition to its repeal of the Holding Company Act, the Energy Act of 2005 authorized the FERC to establish regional reliability organizations authorized to enforce reliability standards, established a process for the FERC to address impediments to the construction of transmission, and established clear responsibility for the FERC to prohibit manipulative energy trading practices.
Alabama Power and Georgia Power are also subject to the provisions of the Federal Power Act or the earlier Federal Water Power Act applicable to licensees with respect to their hydroelectric developments. Among the hydroelectric projects subject to licensing by the FERC are 14 existing Alabama Power generating stations having an aggregate installed capacity of 1,662,400 kilowatts and 18 existing Georgia Power generating stations having an aggregate installed capacity of 1,074,696 kilowatts.
In 2003, Georgia Power started the relicensing process for the Morgan Falls project which is located on the Chattahoochee River near Atlanta, Georgia and submitted the final license application for this facility to the FERC in February 2007. The current license for the Morgan Falls project expires in 2009. In 2007, Georgia Power began the relicensing process for Bartlett’s Ferry which is located on the Chattahoochee River near Columbus, Georgia. The current Bartlett’s Ferry license expires in 2014 and the application for a new license is expected to be submitted to the FERC in 2012. In July 2005, Alabama Power filed two applications with the FERC for new 50-year licenses for its seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan,
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and Bouldin) and for the Lewis Smith and Bankhead developments on the Warrior River. The FERC licenses for all of these nine developments expired in July and August of 2007. The FERC issued an annual license for the Coosa developments on August 8, 2007 and issued an annual license for the Warrior developments on September 6, 2007. These annual licenses provide the FERC with additional time to complete its review of the license applications. In 2006, Alabama Power initiated the process of developing an application to relicense the Martin hydroelectric project located on the Tallapoosa River. The current Martin license will expire in 2013 and the application for a new license is expected to be filed with the FERC in 2011. See MANAGEMENT’S DISCUSSION AND ANALYSIS - FUTURE EARNINGS POTENTIAL - “FERC Matters - Hydro Relicensing” of Alabama Power in Item 7 herein for additional information.
Georgia Power and OPC also have a license, expiring in 2027, for the Rocky Mountain Plant, a pure pumped storage facility of 847,800 kilowatt capacity. See PROPERTIES - “Jointly-Owned Facilities” in Item 2 herein for additional information.
Licenses for all projects, excluding those discussed above, expire in the period 2015-2034 in the case of Alabama Power’s projects and in the period 2014-2039 in the case of Georgia Power’s projects.
Upon or after the expiration of each license, the United States Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee. In the event of takeover or relicensing to another, the original licensee is to be compensated in accordance with the provisions of the Federal Power Act, such compensation to reflect the net investment of the licensee in the project, not in excess of the fair value of the property, plus reasonable damages to other property of the licensee resulting from the severance therefrom of the property. If the FERC does not act on the new license application prior to the expiration of the existing license, the FERC is required to issue annual licenses, under the same terms and conditions of the existing license, until a new license is issued.
Nuclear Regulation
Alabama Power, Georgia Power and Southern Nuclear are subject to regulation by the NRC. The NRC is responsible for licensing and regulating nuclear facilities and materials and for conducting research in support of the licensing and regulatory process, as mandated by the Atomic Energy Act of 1954, as amended; the Energy Reorganization Act of 1974, as amended; and the Nuclear Nonproliferation Act of 1978; and in accordance with the National Environmental Policy Act of 1969, as amended, and other applicable statutes. These responsibilities also include protecting public health and safety, protecting the environment, protecting and safeguarding nuclear materials and nuclear power plants in the interest of national security, and assuring conformity with antitrust laws.
The NRC operating licenses for Plant Vogtle units 1 and 2 currently expire in January 2027 and February 2029, respectively. In January 2002, the NRC granted Georgia Power a 20-year extension of the licenses for both units at Plant Hatch which permits the operation of units 1 and 2 until 2034 and 2038, respectively. Georgia Power filed an application with the NRC in June 2007 to extend the licenses for Plant Vogtle units 1 and 2 for an additional 20 years. In May 2005, the NRC granted Alabama Power a 20-year extension of the licenses for both units at Plant Farley which permits operation of units 1 and 2 until 2037 and 2041, respectively.
See Notes 1 and 9 to the financial statements of Southern Company, Alabama Power, and Georgia Power in Item 8 herein for information on nuclear decommissioning costs and nuclear insurance.
FERC Matters
See MANAGEMENT’S DISCUSSION AND ANALYSIS - FUTURE EARNINGS POTENTIAL - “FERC Matters” of each of the registrants in Item 7 herein for information on matters regarding the FERC.
Environmental Statutes and Regulations
Southern 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. Compliance with these existing environmental requirements involves significant capital and operating costs, a major
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portion of which is expected to be recovered through existing ratemaking provisions. There is no assurance, however, that all such costs will be recovered.
Compliance with the federal Clean Air Act and resulting regulations has been, and will continue to be, a significant focus for Southern Company, each traditional operating company, Southern Power, and SEGCO. In addition, existing environmental laws and regulations may be changed or new laws and regulations may be adopted or otherwise become applicable to Southern Company, the traditional operating companies, or Southern Power, including laws and regulations designed to address global climate change, air quality, water quality or other environmental, public health, and welfare concerns. See MANAGEMENT’S DISCUSSION AND ANALYSIS - FUTURE EARNINGS POTENTIAL - “Environmental Matters” of Southern Company and each of the traditional operating companies in Item 7 herein for additional information about the Clean Air Act and other environmental issues, including the litigation brought by the EPA under the New Source Review provisions of the Clean Air Act and possible climate change legislation and regulation. Also see MANAGEMENT’S DISCUSSION AND ANALYSIS - FUTURE EARNINGS POTENTIAL - “Environmental Matters” and “Global Climate Issues” of Southern Power in Item 7 herein for information about the Clean Air Act, other environmental issues, and possible climate change legislation and regulation.
The traditional operating companies, Southern Power, and SEGCO are unable to predict at this time what additional steps they may be required to take as a result of the implementation of existing or future control requirements for climate, air, water, and hazardous or toxic materials, but such steps could adversely affect system operations and result in substantial additional costs.
The outcome of the matters mentioned above under “Regulation” cannot now be determined, except that these developments may result in delays in obtaining appropriate licenses for generating facilities, increased construction and operating costs, or reduced generation, the nature and extent of which, while not determinable at this time, could be substantial.
Rate Matters
Rate Structure and Cost Recovery Plans
The rates and service regulations of the traditional operating companies are uniform for each class of service throughout their respective service areas. Rates for residential electric service are generally of the block type based upon kilowatt-hours used and include minimum charges. Residential and other rates contain separate customer charges. Rates for commercial service are presently of the block type and, for large customers, the billing demand is generally used to determine capacity and minimum bill charges. These large customers’ rates are generally based upon usage by the customer and include rates with special features to encourage off-peak usage. Additionally, Alabama Power, Gulf Power, and Mississippi Power are generally allowed by their respective state PSCs to negotiate the terms and cost of service to large customers. Such terms and cost of service, however, are subject to final state PSC approval.
Fuel and net purchased energy costs are recovered through specific fuel cost recovery provisions at the traditional operating companies. These fuel cost recovery provisions are adjusted to reflect increases or decreases in such costs as needed. Gulf Power’s and Mississippi Power’s fuel cost recovery provisions are adjusted annually to reflect increases or decreases in such costs. Georgia Power is currently required to file for an adjustment to its fuel cost recovery rate no later than March 1, 2008. Alabama Power’s fuel clause is adjusted as required. Revenues are adjusted for differences between recoverable costs and amounts actually recovered in current rates.
Approved environmental compliance and storm damage costs are recovered at Alabama Power, Gulf Power, and Mississippi Power through cost recovery provisions approved by their respective state PSCs. Within limits approved by their respective PSCs, these rates are adjusted to reflect increases or decreases in such costs as required.
Georgia Power’s environmental compliance costs were recovered in base rates through 2007. Under the 2007 retail rate plan approved by the Georgia PSC, an environmental compliance cost recovery tariff was implemented effective January 1, 2008, to allow for recovery of costs related to environmental controls mandated by state and federal regulations. Georgia Power continues to recover storm damage and new plant costs through its base rates.
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Alabama Power recovers the cost of certificated new plant and purchased power capacity and Gulf Power recovers purchased power capacity and conservation costs through cost recovery provisions which are adjusted as required to reflect increases or decreases in such costs as needed. Revenues are adjusted for differences between recoverable costs and amounts actually recovered in current rates.
See MANAGEMENT’S DISCUSSION AND ANALYSIS - FUTURE EARNINGS POTENTIAL - “PSC Matters” of Southern Company and each of the traditional operating companies in Item 7 herein and Note 3 to the financial statements of Southern Company under “Alabama Power Retail Regulatory Matters” and “Georgia Power Retail Regulatory Matters” and Note 3 to the financial statements of each of the traditional operating companies under “Retail Regulatory Matters” in Item 8 herein for a discussion of rate matters. Also, see Note 1 to the financial statements of Southern Company and each of the traditional operating companies in Item 8 herein for a discussion of recovery of fuel costs, storm damage costs, and environmental compliance costs through rates.
The traditional operating companies and Southern Power are authorized by the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. See MANAGEMENT’S DISCUSSION AND ANALYSIS - FUTURE EARNINGS POTENTIAL - “FERC Matters - Market-Based Rate Authority” of each registrant in Item 7 herein and Note 3 to the financial statements of each registrant under “FERC Matters - Market-Based Rate Authority” in Item 8 herein for a discussion of rate matters.
Integrated Resource Planning
Triennially, Georgia Power must file an IRP with the Georgia PSC that specifies how it intends to meet the future electrical needs of its customers through a combination of demand-side and supply-side resources. The Georgia PSC under state law will certify any new demand-side or supply-side resources. Once certified, the lesser of actual or certified construction costs and purchased power costs will be recoverable through rates.
On July 12, 2007, the Georgia PSC approved Georgia Power’s 2007 IRP including the following provisions:
(1) retiring the coal units at Plant McDonough and replacing them with combined-cycle natural gas units; (2) approving new energy efficiency pilot programs and rate recovery of demand-side management programs; (3) approving pursuit of up to three new renewable generation projects with a Georgia Power ownership interest; and (4) establishing new nuclear units as a preferred option to meet demand in the 2015/2016 timeframe.
In July 2007, the Georgia PSC ordered Georgia Power to issue a RFP, submit the proposals for new base load generation needed in the 2016-2017 timeframe by February 1, 2008, and file an application to certify the chosen resources by May 1, 2008. The RFP was issued in November 2007. In December 2007, Georgia Power requested, and the Georgia PSC approved, extension of the proposal submission until May 1, 2008 and the filing date of Georgia Power’s application to certify the chosen resources until August 1, 2008.
See MANAGEMENT’S DISCUSSION AND ANALYSIS - RESULTS OF OPERATION - “Fuel and Purchased Power Expenses” of Georgia Power in Item 7 herein for information on the Georgia PSC’s approval of PPAs to begin in 2010.
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Employee Relations
The Southern Company system had a total of 26,742 employees on its payroll at December 31, 2007.
*
One of Southern Holdings’ subsidiaries has an employee. Southern Holdings has agreements with SCS whereby all other employee services are rendered at cost.
**
Southern Power has no employees. Southern Power has agreements with SCS and the traditional operating companies whereby employee services are rendered at amounts in compliance with FERC regulations.
The traditional operating companies have separate agreements with local unions of the IBEW generally covering wages, working conditions, and procedures for handling grievances and arbitration. These agreements apply with certain exceptions to operating, maintenance, and construction employees.
Alabama Power has agreements with the IBEW on a five-year contract extending to August 15, 2009. Upon notice given at least 60 days prior to that date, negotiations may be initiated with respect to agreement terms to be effective after such date.
Georgia Power has an agreement with the IBEW covering wages and working conditions, which is in effect through June 30, 2008.
Gulf Power has an agreement with the IBEW covering wages and working conditions, which is in effect through October 14, 2009.
Mississippi Power has an agreement with the IBEW covering wages and working conditions, which is in effect through August 16, 2010.
Southern Nuclear has agreements with the IBEW on a three-year contract extending to June 30, 2008 for Plants Hatch and Vogtle and a three-year contract which is in effect through August 15, 2009 for Plant Farley. Upon notice given at least 60 days prior to these dates, negotiations may be initiated with respect to agreement terms to be effective after such dates.
The agreements also subject the terms of the pension plans for the companies discussed above to collective bargaining with the unions at either a five-year or a 10-year cycle, depending upon union and company actions.
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Item 1A.
Item 1A. RISK FACTORS
In addition to the other information in this Form 10-K, including MANAGEMENT’S DISCUSSION AND ANALYSIS - FUTURE EARNINGS POTENTIAL in Item 7 of each registrant, and other documents filed by Southern Company and/or its subsidiaries with the SEC from time to time, the following factors should be carefully considered in evaluating Southern Company and its subsidiaries. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, Southern Company and/or its subsidiaries.
Risks Related to the Energy Industry
Southern Company and its subsidiaries are subject to substantial governmental regulation. Compliance with current and future regulatory requirements and procurement of necessary approvals, permits, and certificates may result in substantial costs to Southern Company and its subsidiaries.
Southern Company and its subsidiaries, including the traditional operating companies and Southern Power, are subject to substantial regulation from federal, state, and local regulatory agencies. Southern Company and its subsidiaries are required to comply with numerous laws and regulations and to obtain numerous permits, approvals, and certificates from the governmental agencies that regulate various aspects of their businesses, including customer rates, service regulations, retail service territories, sales of securities, asset acquisitions and sales, accounting policies and practices, and the operation of fossil-fuel, hydroelectric, and nuclear generating facilities. For example, the rates charged to wholesale customers by the traditional operating companies and by Southern Power must be approved by the FERC and failure to maintain FERC market-based rate authority may impact the rates charged to wholesale customers. Additionally, the respective state PSCs must approve the traditional operating companies’ rates for retail customers. While the retail rates approved by the respective state PSCs are designed to provide for recovery of costs and a return on invested capital, there can be no assurance that a state PSC will not deem certain costs to be imprudently incurred and not subject to recovery.
Southern Company and its subsidiaries believe the necessary permits, approvals and certificates have been obtained for its existing operations and that their respective businesses are conducted in accordance with applicable laws; however, the impact of any future revision or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to Southern Company or any of its subsidiaries cannot now be predicted. Changes in regulation or the imposition of additional regulations could influence the operating environment of Southern Company and its subsidiaries and may result in substantial costs.
Certain events in the energy markets that are beyond the control of Southern Company and its subsidiaries have increased the level of public and regulatory scrutiny in the energy industry and in the capital markets. The reaction to these events may result in new laws or regulations related to the business operations or the accounting treatment of the existing operations of Southern Company and its subsidiaries which could have a negative impact on the net income or access to capital of Southern Company and its subsidiaries.
Companies in regulated and unregulated electric utility businesses have been under an increased amount of public and regulatory scrutiny with respect to, among other things, accounting practices, financial disclosures, and relationships with independent auditors. This increased scrutiny has led to substantial changes in laws and regulations affecting Southern Company and its subsidiaries, including, among other things, enhanced internal control and auditor independence requirements, financial statement certification requirements, more frequent SEC reviews of financial statements, and accelerated and additional SEC filing requirements. New accounting and disclosure requirements have changed the way Southern Company and its subsidiaries are required to record revenues, expenses, assets, and liabilities. Southern Company expects continued regulatory focus on accounting and financial reporting issues. Disruptions in the industry and any resulting additional regulations may have a negative impact on the net income or access to capital of Southern Company and its subsidiaries.
General Risks Related to Operation of Southern Company’s Utility Subsidiaries
The regional power market in which Southern Company and its utility subsidiaries compete may have changing transmission regulatory structures, which could affect the ownership of these assets and related
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revenues and expenses.
The traditional operating companies currently own and operate transmission facilities as part of a vertically integrated utility. Transmission revenues are not separated from generation and distribution revenues in their approved retail rates. Current FERC efforts that may potentially change the regulatory and/or operational structure of transmission include rules related to the standardization of generation interconnection, as well as an inquiry into, among other things, market power by vertically integrated utilities. The financial condition, net income, and cash flows of Southern Company and its utility subsidiaries could be adversely affected by future changes in the federal regulatory or operational structure of transmission.
Deregulation or restructuring in the electric industry may result in increased competition and unrecovered costs which could negatively impact the net income of Southern Company and the traditional operating companies and the value of their respective assets.
Increased competition resulting from restructuring efforts, could have a significant adverse financial impact on Southern Company and the traditional operating companies. Any adoption in the territories served by the traditional operating companies of retail competition and the unbundling of regulated energy service could have a significant adverse financial impact on Southern Company and the traditional operating companies due to an impairment of assets, a loss of retail customers, lower profit margins, an inability to recover reasonable costs, or increased costs of capital. Southern Company and the traditional operating companies cannot predict if or when they may be subject to changes in legislation or regulation, nor can Southern Company and the traditional operating companies predict the impact of these changes.
Additionally, the electric utility industry has experienced a substantial increase in competition at the wholesale level. As a result of changes in federal law and regulatory policy, competition in the wholesale electricity market has greatly increased due to a greater participation by traditional electricity suppliers, non-utility generators, IPPs, wholesale power marketers, and brokers and due to the trading of energy futures contracts on various commodities exchanges. In addition, FERC rules on transmission service are designed to facilitate competition in the wholesale market on a nationwide basis by providing greater flexibility and more choices to wholesale power customers.
Changes to the criteria used by the FERC for approval of market-based rate authority may negatively impact the traditional operating companies’ and Southern Power’s ability to charge market-based rates which could negatively impact the net income and cash flow of Southern Company, the traditional operating companies, and Southern Power.
Each of the traditional operating companies and Southern Power have authorization from the FERC to sell power to nonaffiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based sale to an affiliate.
In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales by any subsidiary of Southern Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level.
In late June and July 2007, hearings were held in this proceeding and the presiding administrative law judge issued an initial decision on November 9, 2007 regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the traditional operating companies and Southern Power to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates, and could also result in refunds of up to $19.7 million, plus interest. Southern Company and its subsidiaries believe that there is no meritorious basis for this proceeding and are vigorously defending themselves in this matter.
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On June 21, 2007, the FERC issued its final rule regarding market-based rate authority. The FERC generally retained its current market-based rate standards. The impact of this order and its effect on the generation dominance proceeding cannot now be determined.
Risks Related to Environmental and Climate Change Legislation and Regulation
Southern Company’s and the traditional operating companies’ costs of compliance with environmental laws are significant. The costs of compliance with future environmental laws, including laws and regulations designed to address global climate change, and the incurrence of environmental liabilities could affect unit retirement decisions and negatively impact the net income, cash flows, and financial condition of Southern Company, the traditional operating companies, or Southern Power.
Southern Company, the traditional operating companies, and Southern Power are subject to extensive federal, state, and local environmental requirements which, among other things, regulate air emissions, water discharges, and the management of hazardous and solid waste in order to adequately protect the environment. Compliance with these legal requirements requires Southern Company, the traditional operating companies, and Southern Power to commit significant expenditures for installation of pollution control equipment, environmental monitoring, emissions fees, and permits at all of their respective facilities. These expenditures are significant and Southern Company, the traditional operating companies, and Southern Power expect that they will increase in the future. Through 2007, Southern Company had invested approximately $4.7 billion in capital projects to comply with these requirements, with annual totals of $1.5 billion, $661 million, and $423 million for 2007, 2006, and 2005, respectively. Southern Company expects that capital expenditures to assure compliance with existing and new statutes and regulations will be an additional $1.8 billion, $1.5 billion, and $0.6 billion for 2008, 2009, and 2010, respectively. Because Southern Company’s compliance strategy is impacted by changes to existing environmental laws, statutes, and regulations, the cost, availability, and existing inventory of emission allowances, and Southern Company’s fuel mix, the ultimate outcome cannot be determined at this time.
Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent.
If Southern Company, the traditional operating companies, or Southern Power fail to comply with environmental laws and regulations, even if caused by factors beyond their control, that failure may result in the assessment of civil or criminal penalties and fines. The EPA has filed civil actions against Alabama Power and Georgia Power alleging violations of the new source review provisions of the Clean Air Act. Southern Company is a party to suits alleging its emissions of carbon dioxide, a greenhouse gas, contribute to global warming. An adverse outcome in either of these cases could require substantial capital expenditures that cannot be determined at this time, and could possibly require payment of substantial penalties. Such expenditures could affect unit retirement and replacement decisions, and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
Existing environmental laws and regulations may be revised or new laws and regulations related to global climate change, air quality, or other environmental and health concerns may be adopted or become applicable to Southern Company, the traditional operating companies, and Southern Power. For example, legislative proposals that would impose mandatory requirements on greenhouse gas emissions continue to be considered in Congress. In addition, some states are considering or have undertaken actions to regulate and reduce greenhouse gas emissions. In July 2007, for example, the Governor of the State of Florida signed three executive orders addressing reduction of greenhouse gas emissions within the state, including statewide emission reduction targets beginning in 2017. In 2007, the Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. The EPA is currently developing its response to this decision. Regulatory decisions that will follow from this response may have implications for both new and existing stationary sources, such as power plants.
New or revised laws and regulations or new interpretations of existing laws and regulations, such as those related to climate change, could affect unit retirement and replacement decisions and/or result in significant additional expense and operating restrictions on the facilities of the traditional operating companies or Southern Power or increased
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compliance costs which may not be fully recoverable from customers and would therefore reduce the net income of Southern Company, the traditional operating companies, or Southern Power. The cost impact of such legislation, regulation, or new interpretations would depend upon the specific requirements enacted and cannot be determined at this time.
Risks Related to Southern Company and its Business
Southern Company may be unable to meet its ongoing and future financial obligations and to pay dividends on its common stock if its subsidiaries are unable to pay upstream dividends or repay funds to Southern Company.
Southern Company is a holding company and, as such, Southern Company has no operations of its own. Substantially all of Southern Company’s consolidated assets are held by subsidiaries. Southern Company’s ability to meet its financial obligations and to pay dividends on its common stock at the current rate is primarily dependent on the net income and cash flows of its subsidiaries and their ability to pay upstream dividends or to repay funds to Southern Company. Prior to funding Southern Company, Southern Company’s subsidiaries have financial obligations that must be satisfied, including among others, debt service and preferred and preference stock dividends. Southern Company’s subsidiaries are separate legal entities and have no obligation to provide Southern Company with funds for its payment obligations.
The financial performance of Southern Company and its subsidiaries may be adversely affected if its subsidiaries are unable to successfully operate their facilities.
Southern Company’s financial performance depends on the successful operation of its subsidiaries’ electric generating, transmission, and distribution facilities. Operating these facilities involves many risks, including:
•
operator error or failure of equipment or processes;
•
operating limitations that may be imposed by environmental or other regulatory requirements;
•
labor disputes;
•
terrorist attacks;
•
fuel or material supply interruptions;
•
compliance with mandatory reliability standards; and
•
catastrophic events such as fires, earthquakes, explosions, floods, droughts, hurricanes, pandemic health events such as an avian influenza, or other similar occurrences.
A decrease or elimination of revenues from power produced by the electric generating facilities or an increase in the cost of operating the facilities would reduce the net income and cash flows and could adversely impact the financial condition of the affected traditional operating company or Southern Power and of Southern Company.
The revenues of Southern Company, the traditional operating companies, and Southern Power depend in part on sales under PPAs. The failure of a counterparty to one of these PPAs to perform its obligations, or the failure to renew the PPAs, could have a negative impact on the net income and cash flows of the affected traditional operating company or Southern Power and of Southern Company.
Most of Southern Power’s generating capacity has been sold to purchasers under PPAs having initial terms of five to 15 years. In addition, the traditional operating companies enter into PPAs with non-affiliated parties. Revenues are dependent on the continued performance by the purchasers of their obligations under these PPAs. Even though Southern Power and the traditional operating companies have a rigorous credit evaluation process, the failure of one of the purchasers to perform its obligations could have a negative impact on the net income and cash flows of the affected traditional operating company or Southern Power and of Southern Company. Although these credit
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evaluations take into account the possibility of default by a purchaser, actual exposure to a default by a purchaser may be greater than the credit evaluation predicts. Additionally, neither Southern Power nor any traditional operating company can predict whether the PPAs will be renewed at the end of their respective terms or on what terms any renewals may be made. If a PPA is not renewed, a replacement PPA cannot be assured.
Southern Company, the traditional operating companies, and Southern Power may incur additional costs or delays in the construction of new plants or environmental facilities and may not be able to recover their investment. The facilities of Southern Company, the traditional operating companies, and Southern Power require ongoing capital expenditures.
Certain of the traditional operating companies and Southern Power are in the process of constructing new generating facilities and adding environmental controls equipment at existing generating facilities. Southern Company intends to continue its strategy of developing and constructing other new facilities, expanding existing facilities and adding environmental control equipment. The completion of these types of projects without delays or cost overruns is subject to substantial risks, including:
•
shortages and inconsistent quality of equipment, materials, and labor, including environmental laws and regulations;
•
work stoppages;
•
permits, approvals, and other regulatory matters;
•
adverse weather conditions;
•
unforeseen engineering problems;
•
environmental and geological conditions;
•
delays or increased costs to interconnect its facilities to transmission grids;
•
unanticipated cost increases; and
•
attention to other projects.
Tightening labor markets in the Southeast and increasing costs of materials have resulted in increasing cost estimates for Southern Company’s subsidiaries’ construction projects. If a traditional operating company or Southern Power is unable to complete the development or construction of a facility or decides to delay or cancel construction of a facility, it may not be able to recover its investment in that facility. In addition, construction delays and contractor performance shortfalls can result in the loss of revenues and may, in turn, adversely affect the net income and financial position of a traditional operating company or Southern Power and of Southern Company. Furthermore, if construction projects are not completed according to specification, a traditional operating company or Southern Power and Southern Company may incur liabilities and suffer reduced plant efficiency, higher operating costs, and reduced net income.
Once facilities come into commercial operation, ongoing capital expenditures are required to maintain reliable levels of operation. Significant portions of the traditional operating companies’ existing facilities were constructed many years ago. Older generation equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with changing environmental requirements, or to provide reliable operations.
Changes in technology may make Southern Company’s electric generating facilities owned by the traditional operating companies, and Southern Power less competitive.
A key element of the business model of Southern Company, the traditional operating companies, and Southern Power is that generating power at central station power plants achieves economies of scale and produces power at a
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competitive cost. There are distributed generation technologies that produce power, including fuel cells, microturbines, wind turbines, and solar cells. It is possible that advances in technology will reduce the cost of alternative methods of producing power to a level that is competitive with that of most central station power electric production. If this were to happen and if these technologies achieved economies of scale, the market share of Southern Company, the traditional operating companies, and Southern Power could be eroded, and the value of their respective electric generating facilities could be reduced. It is also possible that rapid advances in central station power generation technology could reduce the value of the current electric generating facilities owned by Southern Company, the traditional operating companies, and Southern Power. Changes in technology could also alter the channels through which retail electric customers buy or utilize power, which could reduce the revenues or increase the expenses of Southern Company, the traditional operating companies, or Southern Power.
Operation of nuclear facilities involves inherent risks, including environmental, health, regulatory, terrorism and financial risks that could result in fines or the closure of Southern Company’s nuclear units owned by Alabama Power or Georgia Power, and which may present potential exposures in excess of insurance coverage.
Alabama Power owns two nuclear units and Georgia Power holds undivided interests in, and contracts for operation of, four nuclear units. These six units are operated by Southern Nuclear and represent approximately 3,680 megawatts, or 8.8%, of Southern Company’s generation capacity as of December 31, 2007. These nuclear facilities are subject to environmental, health and financial risks such as on-site storage of spent nuclear fuel, the ability to dispose of such spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, potential liabilities arising out of the operation of these facilities, and the threat of a possible terrorist attack. Alabama Power and Georgia Power maintain decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks; however, it is possible that damages could exceed the amount of insurance coverage.
The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. NRC orders or new regulations related to increased security measures and any future safety requirements promulgated by the NRC could require Alabama Power and Georgia Power to make substantial operating and capital expenditures at their nuclear plants. In addition, although Alabama Power, Georgia Power, and Southern Company have no reason to anticipate a serious nuclear incident at their plants, if an incident did occur, it could result in substantial costs to Alabama Power or Georgia Power and Southern Company. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.
In addition, potential terrorist threats and increased public scrutiny of utilities could result in increased nuclear licensing or compliance costs that are difficult or impossible to predict.
The generation and energy marketing operations of Southern Company, the traditional operating companies, and Southern Power are subject to risks, many of which are beyond their control, including changes in power prices and fuel costs, that may reduce Southern Company’s, the traditional operating companies,’ and Southern Power’s revenues and increase costs.
The generation and energy marketing operations of Southern Company, the traditional operating companies, and Southern Power are subject to changes in power prices or fuel costs, which could increase the cost of producing power or decrease the amount Southern Company, the traditional operating companies, and Southern Power receive from the sale of power. The market prices for these commodities may fluctuate significantly over relatively short periods of time. Southern Company, the traditional operating companies, and Southern Power attempt to mitigate risks associated with fluctuating fuel costs by passing these costs on to customers through the traditional operating companies’ fuel cost recovery clauses or through PPAs. Among the factors that could influence power prices and fuel costs are:
•
prevailing market prices for coal, natural gas, uranium, fuel oil, and other fuels used in the generation facilities of the traditional operating companies and Southern Power including associated transportation costs, and supplies of such commodities;
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•
demand for energy and the extent of additional supplies of energy available from current or new competitors;
•
liquidity in the general wholesale electricity market;
•
weather conditions impacting demand for electricity;
•
seasonality;
•
transmission or transportation constraints or inefficiencies;
•
availability of competitively priced alternative energy sources;
•
forced or unscheduled plant outages for the Southern Company system, its competitors, or third party providers;
•
the financial condition of market participants;
•
the economy in the service territory, nation and worldwide, including the impact of economic conditions on industrial and commercial demand for electricity and the worldwide demand for fuels;
•
natural disasters, wars, embargos, acts of terrorism, and other catastrophic events; and
•
federal, state, and foreign energy and environmental regulation and legislation.
Certain of these factors could increase the expenses of the traditional operating companies or Southern Power and Southern Company. For the traditional operating companies, such increases may not be fully recoverable through rates. Other of these factors could reduce the revenues of the traditional operating companies or Southern Power and Southern Company.
As a result of increasing fuel costs, the traditional operating companies have accrued significant underrecovered fuel cost balances. In addition, Gulf Power has a significant underrecovered balance in its storm cost recovery reserve as a result of Hurricanes Dennis and Katrina. The traditional operating companies may experience similar deficit balances following future storms. While the traditional operating companies are generally authorized to recover underrecovered fuel costs through fuel cost recovery clauses and storm recovery costs through special rate provisions administered by the respective PSCs, recovery may be denied if costs are deemed to be imprudently incurred and delays in the authorization of such recovery could negatively impact the cash flows of the affected traditional operating company and Southern Company.
The use of derivative contracts by Southern Company and its subsidiaries in the normal course of business could result in financial losses that negatively impact the net income of Southern Company and its subsidiaries.
Southern Company and its subsidiaries, including the traditional operating companies and Southern Power, use derivative instruments, such as swaps, options, futures, and forwards, to manage their commodity and financial market risks and, to a lesser extent, engage in limited trading activities. Southern Company and its subsidiaries could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the value of the reported fair value of these contracts.
The traditional operating companies and Southern Power may not be able to obtain adequate fuel supplies, which could limit their ability to operate their facilities.
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The traditional operating companies and Southern Power purchase fuel, including coal, natural gas, uranium, and fuel oil, from a number of suppliers. Disruption in the delivery of fuel, including disruptions as a result of, among other things, transportation delays, weather, labor relations, force majeure events, or environmental regulations affecting any of these fuel suppliers, could limit the ability of the traditional operating companies and Southern Power to operate their respective facilities, and thus reduce the net income of the affected traditional operating company or Southern Power and Southern Company.
The traditional operating companies are dependent on coal for much of their electric generating capacity. Each traditional operating company has coal supply contracts in place; however, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply coal to the traditional operating companies. The suppliers under these agreements may experience financial or technical problems which inhibit their ability to fulfill their obligations to the traditional operating companies. In addition, the suppliers under these agreements may not be required to supply coal to the traditional operating companies under certain circumstances, such as in the event of a natural disaster. If the traditional operating companies are unable to obtain their coal requirements under these contracts, the traditional operating companies may be required to purchase their coal requirements at higher prices, which may not be fully recoverable through rates.
In addition, Southern Power in particular, and the traditional operating companies to a lesser extent, are dependent on natural gas for a portion of their electric generating capacity. Natural gas supplies can be subject to disruption in the event production or distribution is curtailed. For example, in connection with the 2005 hurricanes in the Gulf of Mexico, production and distribution of natural gas was limited for a period of time, resulting in shortages and significant increases in the price of natural gas. In addition, world market conditions for fuels, including the policies of the Organization of Petroleum Exporting Countries, can impact the price and availability of natural gas.
Demand for power could exceed supply capacity, resulting in increased costs for purchasing capacity in the open market or building additional generation capabilities.
Through the traditional operating companies and Southern Power, Southern Company is currently obligated to supply power to retail customers and wholesale customers under long-term PPAs. At peak times, the demand for power required to meet this obligation could exceed Southern Company’s available generation capacity. Market or competitive forces may require that the traditional operating companies or Southern Power purchase capacity on the open market or build additional generation capabilities. Because regulators may not permit the traditional operating companies to pass all of these purchase or construction costs on to their customers, the traditional operating companies may not be able to recover any of these costs or may have exposure to regulatory lag associated with the time between the incurrence of costs of purchased or constructed capacity and the traditional operating companies’ recovery in customers’ rates. Under Southern Power’s long-term fixed price PPAs, Southern Power would not have the ability to recover any of these costs. These situations could have negative impacts on net income and cash flows for the affected traditional operating company or Southern Power and Southern Company.
The operating results of Southern Company, the traditional operating companies, and Southern Power are affected by weather conditions and may fluctuate on a seasonal and quarterly basis.
Electric power supply is generally a seasonal business. In many parts of the country, demand for power peaks during the summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. As a result, the overall operating results of Southern Company, the traditional operating companies, and Southern Power in the future may fluctuate substantially on a seasonal basis. In addition, Southern Company, the traditional operating companies, and Southern Power have historically sold less power when weather conditions are milder. Unusually mild weather in the future could reduce the revenues, net income, available cash and borrowing ability of Southern Company, the traditional operating companies, and Southern Power.
Mirant and The Official Committee of Unsecured Creditors of Mirant Corporation have filed a claim against Southern Company seeking substantial monetary damages in connection with transfers made by Mirant to Southern Company prior to the Mirant spin-off.
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Mirant was an energy company with businesses that included independent power projects and energy trading and risk management companies in the U.S. and selected other countries. It was a wholly-owned subsidiary of Southern Company until its initial public offering in October 2000. In April 2001, Southern Company completed a spin-off to its shareholders of its remaining ownership, and Mirant became an independent corporate entity.
In July 2003, Mirant and certain of its affiliates filed for voluntary reorganization under Chapter 11 of the Bankruptcy Code. In January 2006, Mirant’s plan of reorganization became effective, and Mirant emerged from bankruptcy. As part of the plan, Mirant transferred substantially all of its assets and its restructured debt to a new corporation that adopted the name Mirant Corporation (Reorganized Mirant).
In December 2004, as a result of concluding an IRS audit for the tax years 2000 and 2001, Southern Company paid approximately $39 million in additional tax and interest related to Mirant tax items and filed a claim in Mirant’s bankruptcy case for that amount. Through December 2007, Southern Company received from the IRS approximately $36 million in refunds related to Mirant. Southern Company believes it has a right to recoup the $39 million tax payment owed by Mirant from such tax refunds. As a result, Southern Company intends to retain the tax refunds and reduce its claim against Mirant for the payment of Mirant taxes by the amount of such refunds. MC Asset Recovery, a special purpose subsidiary of Reorganized Mirant, has objected to and sought to equitably subordinate the Southern Company tax claim in its fraudulent transfer litigation against Southern Company. Southern Company has reserved the approximately $3 million amount remaining with respect to its Mirant tax claim.
If Southern Company is ultimately required to make any additional payments either with respect to the IRS audit or its contingent obligations under guarantees of Mirant subsidiaries, Mirant’s indemnification obligation to Southern Company for these additional payments, if allowed, would constitute unsecured claims against Mirant, entitled to stock in Reorganized Mirant.
In June 2005, Mirant, as a debtor in possession, and The Official Committee of Unsecured Creditors of Mirant Corporation filed a complaint against Southern Company in the U.S. Bankruptcy Court for the Northern District of Texas, which was amended in July 2005, February 2006, May 2006, and March 2007. In January 2006, MC Asset Recovery was substituted as plaintiff. The fourth amended complaint alleges that Southern Company caused Mirant to engage in certain fraudulent transfers and to pay illegal dividends to Southern Company prior to the spin-off. The complaint also seeks to recharacterize certain advances from Southern Company to Mirant for investments in energy facilities from debt to equity. The complaint further alleges that Southern Company is liable to Mirant’s creditors for the full amount of Mirant’s liability and that Southern Company breached its fiduciary duties to Mirant and its creditors, caused Mirant to breach fiduciary duties to its creditors, and aided and abetted breaches of fiduciary duties by Mirant’s directors and officers. The complaint also seeks recoveries under theories of restitution, unjust enrichment, and alter ego. In addition, the complaint alleges a claim under the Federal Debt Collection Procedure Act (FDCPA) to void certain transfers from Mirant to Southern Company. MC Asset Recovery claims to have standing to assert violations of the FDCPA and to recover property on behalf of the Mirant debtors’ estates. The complaint seeks monetary damages in excess of $2 billion plus interest, punitive damages, attorneys’ fees, and costs. Finally, the complaint includes an objection to Southern Company’s pending claims against Mirant in the Bankruptcy Court (which relate to reimbursement under the separation agreements of payments such as income taxes, interest, legal fees, and other guarantees described in Note 7 to the financial statements of Southern Company in Item 8 herein) and seeks equitable subordination of Southern Company’s claims to the claims of all other creditors. Southern Company served an answer to the complaint in April 2007.
In February 2006, Southern Company’s motion to transfer the case to the U.S. District Court for the Northern District of Georgia was granted. In May 2006, Southern Company filed a motion for summary judgment seeking entry of judgment against the plaintiff as to all counts in the complaint. In December 2006, the U.S. District Court for the Northern District of Georgia granted in part and denied in part the motion. As a result, certain breach of fiduciary duty claims alleged in earlier versions of the complaint were barred; all other claims may proceed. Southern Company believes there is no meritorious basis for the claims in the complaint and is vigorously defending itself in this action. The ultimate outcome of these matters cannot be determined at this time.
IRS challenges to Southern Company’s income tax deductions taken in connection with three international leveraged lease transactions could result in the payment of substantial additional interest and penalties and
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could materially impact Southern Company’s cash flow and net income.
Southern Company undergoes audits by the IRS for each of its tax years. The IRS has completed its audits of Southern Company’s consolidated federal income tax returns for all years prior to 2004. The IRS challenged Southern Company’s deductions related to three international lease transactions (SILO or sale-in-lease-out transactions), in connection with its audits of Southern Company’s 2000 through 2003 tax returns. In the third quarter 2006, Southern Company paid the full amount of the disputed tax and the applicable interest on the SILO issue for tax years 2000 and 2001 and filed a claim for refund which was denied by the IRS. The disputed tax amount was $79 million and the related interest approximately $24 million for these tax years. This payment, and the subsequent IRS disallowance of the refund claim, closed the issue with the IRS and Southern Company initiated litigation in the U.S. District Court for the Northern District of Georgia for a complete refund of tax and interest paid for the 2000 and 2001 tax years. The IRS also challenged the SILO deductions for the tax years 2002 and 2003. The estimated amount of disputed tax and interest for these tax years was approximately $83 million and $15 million, respectively. The tax and interest for these tax years was paid to the IRS in the fourth quarter 2006. Southern Company has accounted for both payments in 2006 as deposits. For the tax years 2000 through 2007, Southern Company has claimed approximately $330 million in tax benefits related to these SILO transactions challenged by the IRS. These tax benefits relate to timing differences and do not impact total net income. Southern Company believes these transactions are valid leases for U.S. tax purposes and the related deductions are allowable. Southern Company is continuing to pursue resolution of these matters; however, the ultimate outcome cannot now be determined. In addition, the U.S. Senate is currently considering legislation that would disallow tax benefits after December 31, 2007 for SILO losses and other international leveraged lease transactions (such as lease-in-lease-out transactions). The ultimate impact on Southern Company’s net income will be dependent on the outcome of the pending litigation and proposed legislation, but could be significant, and potentially material.
Risks Related to Market and Economic Volatility
The business of Southern Company, the traditional operating companies, and Southern Power is dependent on their ability to successfully access capital markets. The inability of Southern Company, any traditional operating company or Southern Power to access capital may limit its ability to execute its business plan or pursue improvements and make acquisitions that Southern Company, the traditional operating companies, or Southern Power may otherwise rely on for future growth.
Southern Company, the traditional operating companies, and Southern Power rely on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flow from their respective operations. If Southern Company, any traditional operating company, or Southern Power is not able to access capital at competitive rates, its ability to implement its business plan or pursue improvements and make acquisitions that Southern Company, the traditional operating companies, or Southern Power may otherwise rely on for future growth will be limited. Each of Southern Company, the traditional operating companies, and Southern Power believes that it will maintain sufficient access to these financial markets based upon current credit ratings. However, certain market disruptions or a downgrade of the credit rating of Southern Company, any traditional operating company, or Southern Power may increase its cost of borrowing or adversely affect its ability to raise capital through the issuance of securities or other borrowing arrangements. Such disruptions could include:
•
an economic downturn or uncertainty;
•
the bankruptcy of an unrelated energy company;
•
capital market conditions generally;
•
market prices for electricity and gas;
•
terrorist attacks or threatened attacks on Southern Company’s facilities or unrelated energy companies;
•
war or threat of war; or
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•
the overall health of the utility industry.
Southern Company, the traditional operating companies, and Southern Power are subject to risks associated with a changing economic environment, including their ability to obtain insurance, the financial stability of their respective customers, and their ability to raise capital.
The threat of terrorism and the hurricanes that affected the Gulf Coast, among other things, have had disruptive effects on the insurance industry. The availability of insurance covering risks that Southern Company, the traditional operating companies, Southern Power, and their respective competitors typically insure against may decrease, and the insurance that Southern Company, the traditional operating companies, and Southern Power are able to obtain may have higher deductibles, higher premiums, and more restrictive policy terms. Any economic downturn or disruption of financial markets could negatively affect the financial stability of their respective customers and counterparties. These factors could adversely affect Southern Company’s subsidiaries’ ability to achieve energy sales growth, thereby decreasing Southern Company’s level of future net income.
Certain of the traditional operating companies have substantial investments in the Gulf Coast region which can be subject to major storm activity. The ability of the traditional operating companies to recover costs and replenish reserves in the event of a major storm, other natural disaster, terrorist attack, or other catastrophic event generally will require regulatory action.
Each traditional operating company maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generating facilities and other property. In September 2004, Hurricane Ivan hit the Gulf coast of Florida and Alabama, causing significant damage to the service areas of Alabama Power and Gulf Power. In July and August 2005, Hurricanes Dennis and Katrina, respectively, hit the Gulf coast of the United States and caused significant damage in the service areas of Gulf Power, Alabama Power, and Mississippi Power. In each case, costs to the respective traditional operating companies exceeded their respective storm cost reserves and insurance coverage and were subsequently approved for recovery by their respective state PSCs. In the event a traditional operating company experiences a natural disaster, terrorist attack, or other catastrophic event, recovery of costs in excess of reserves and insurance coverage is subject to the approval of its state PSC. While the traditional operating companies generally are entitled to recover prudently incurred costs incurred in connection with such an event, any denial by the applicable state PSC or delay in recovery of any portion of such costs could have a material negative impact on a traditional operating company’s and Southern Company’s results of operations and/or cash flows.
Item 1B.
Item 1B. UNRESOLVED STAFF COMMENTS.
None.
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Item 2.
Item 2. PROPERTIES
Electric Properties - The Electric Utilities
The traditional operating companies, Southern Power, and SEGCO, at December 31, 2007, owned and/or operated 34 hydroelectric generating stations, 34 fossil fuel generating stations, 3 nuclear generating stations, and 12 combined cycle/cogeneration stations. The amounts of capacity for each company are shown in the table below.
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(6)
Represents 50% of the plant which is owned as tenants in common by Gulf Power and Mississippi Power.
(7)
SEGCO is jointly-owned by Alabama Power and Georgia Power. See BUSINESS in Item 1 herein for additional information.
(8)
Capacity shown is Georgia Power’s portion (50.1%) of total plant capacity.
(9)
Capacity shown is Georgia Power’s portion (45.7%) of total plant capacity.
(10)
Capacity shown represents 33 1/3% of total plant capacity. Georgia Power owns a 1/3 interest in the unit with 100% use of the unit from June through September. Progress Energy Florida operates the unit.
(11)
Generation is dedicated to a single industrial customer.
(12)
Capacity shown is Southern Power’s portion (65%) of total plant capacity.
(13)
Capacity shown is Georgia Power’s portion (25.4%) of total plant capacity. OPC operates the plant.
Except as discussed below under “Titles to Property,” the principal plants and other important units of the traditional operating companies, Southern Power, and SEGCO are owned in fee by the respective companies. It is the opinion of management of each such company that its operating properties are adequately maintained and are substantially in good operating condition.
Mississippi Power owns a 79-mile length of 500-kilovolt transmission line which is leased to Entergy Gulf States. The line, completed in 1984, extends from Plant Daniel to the Louisiana state line. Entergy Gulf States is paying a use fee over a 40-year period covering all expenses and the amortization of the original $57 million cost of the line. At December 31, 2007, the unamortized portion of this cost was approximately $25 million.
The all-time maximum demand on the traditional operating companies, Southern Power, and SEGCO was 38,777,000 kilowatts and occurred on August 22, 2007. This amount excludes demand served by capacity retained by MEAG, OPC, and SEPA. The reserve margin for the traditional operating companies, Southern Power, and SEGCO at that time was 11.2%. See SELECTED FINANCIAL DATA in Item 6 herein for additional information on peak demands.
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Jointly-Owned Facilities
Alabama Power, Georgia Power, and Southern Power have undivided interests in certain generating plants and other related facilities to or from non-affiliated parties. The percentages of ownership are as follows:
Alabama Power and Georgia Power have contracted to operate and maintain the respective units in which each has an interest (other than Rocky Mountain and Intercession City) as agent for the joint owners. SCS provides operation and maintenance services for Plant Stanton A.
In addition, Georgia Power has commitments regarding a portion of a five percent interest in Plant Vogtle owned by MEAG that are in effect until the later of retirement of the plant or the latest stated maturity date of MEAG’s bonds issued to finance such ownership interest. The payments for capacity are required whether any capacity is available. The energy cost is a function of each unit’s variable operating costs. Except for the portion of the capacity payments related to the Georgia PSC’s disallowances of Plant Vogtle costs, the cost of such capacity and energy is included in purchased power from non-affiliates in Georgia Power’s statements of income in Item 8 herein.
Titles to Property
The traditional operating companies’, Southern Power’s, and SEGCO’s interests in the principal plants (other than certain pollution control facilities, one small hydroelectric generating station leased by Georgia Power, combined cycle units at Plant Daniel leased by Mississippi Power and the land on which five combustion turbine generators of Mississippi Power are located, which is held by easement) and other important units of the respective companies are owned in fee by such companies, subject only to the liens pursuant to pollution control bonds of Alabama Power and Gulf Power on specific pollution control facilities. As of January 26, 2007, Gulf Power’s mortgage indenture and the lien on its principal property were discharged. See Note 6 to the financial statements of Southern Company, Alabama Power, and Gulf Power under “Assets Subject to Lien” and Note 7 to the financial statements of Mississippi Power under “Operating Leases - Plant Daniel Combined Cycle Generating Units” in Item 8 herein for additional information. The traditional operating companies own the fee interests in certain of their principal plants as tenants in common. See “Jointly-Owned Facilities” herein for additional information. Properties such as electric transmission and distribution lines and steam heating mains are constructed principally on rights-of-way which are maintained under franchise or are held by easement only. A substantial portion of lands submerged by reservoirs is held under flood right easements.
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Item 3.
Item 3. LEGAL PROCEEDINGS
(1) United States of America v. Alabama Power (United States District Court for the Northern District of Alabama)
United States of America v. Georgia Power and Savannah Electric (United States District Court for the Northern District of Georgia)
See “Environmental Matters - New Source Review Actions” in Note 3 to Southern Company’s and each traditional operating company’s financial statements in Item 8 herein for information.
(2) Environmental Remediation
See “Environmental Matters - Environmental Remediation” in Note 3 to the financial statements of Southern Company, Georgia Power, Gulf Power, and Mississippi Power and “Retail Regulatory Matters - Environmental Compliance Overview Plan” in Note 3 to the financial statements of Mississippi Power in Item 8 herein for information related to environmental remediation.
(3) In re: Mirant Corporation, et al. (United States Bankruptcy Court for the Northern District of Texas)
See “Mirant Matters - Mirant Bankruptcy” in Note 3 to Southern Company’s financial statements in Item 8 herein for information.
(4) MC Asset Recovery, LLC v. Southern Company (United States District Court for the Northern District of Georgia) (formerly styled In re: Mirant Corporation, et al. in the United States Bankruptcy Court for the Northern District of Texas)
See “Mirant Matters - MC Asset Recovery Litigation” in Note 3 to Southern Company’s financial statements in Item 8 herein for information.
(5) In re: Mirant Corporation Securities Litigation (United States District Court for the Northern District of Georgia)
See “Mirant Matters - Mirant Securities Litigation” in Note 3 to Southern Company’s financial statements in Item 8 herein for information.
(6) Right of Way Litigation
See “Right of Way Litigation” in Note 3 to Southern Company’s, Georgia Power’s, Gulf Power’s, and Mississippi Power’s financial statements in Item 8 herein for information.
See Note 3 to each registrant’s financial statements in Item 8 herein for descriptions of additional legal and administrative proceedings discussed therein.
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Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Southern Company, Alabama Power, Gulf Power, Mississippi Power, and Southern Power
None.
Georgia Power
By written consent, in lieu of a special meeting of the sole common shareholder of Georgia Power, effective October 8, 2007, the sole shareholder approved an amendment to the Charter of Georgia Power to establish a new series of preference stock designated as the “6.50% Series 2007A Preference Stock, Non-Cumulative, Par Value $100 Per Share” (Amendment).
All of the 9,261,500 outstanding shares of Georgia Power’s common stock were owned by Southern Company and were voted in favor of the Amendment.
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EXECUTIVE OFFICERS OF SOUTHERN COMPANY
(Identification of executive officers of Southern Company is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2007.
David M. Ratcliffe
Chairman, President, Chief Executive Officer, and Director
Age 59
Elected in 1999. President since April 2004; Chairman and Chief Executive Officer since July 2004. Previously served as Chief Executive Officer of Georgia Power from June 1999 to April 2004; and President of Georgia Power from June 1999 to December 2003.
W. Paul Bowers
Executive Vice President and Chief Financial Officer
Age 51
Elected in 2001. Executive Vice President and Chief Financial Officer since February 1, 2008 and Executive Vice President since May 2007. Previously served as President of Southern Company Generation, a business unit of Southern Company, and Executive Vice President of SCS since May 2001; and President and Chief Executive Officer of Southern Power from May 2001 through March 2005.
Thomas A. Fanning
Executive Vice President and Chief Operating Officer
Age 50
Elected in 2003. Executive Vice President and Chief Operating Officer since February 1, 2008. Previously served as Executive Vice President and Chief Financial Officer from May 2007 through January 2008; Executive Vice President, Chief Financial Officer, and Treasurer from April 2003 to May 2007; and President, Chief Executive Officer, and Director of Gulf Power from 2002 to April 2003.
Michael D. Garrett
Executive Vice President
Age 58
Elected in 2004. Executive Vice President since January 1, 2004. He also serves as President and Director of Georgia Power since January 1, 2004 and Chief Executive Officer of Georgia Power since April 2004. Previously served as President, Chief Executive Officer, and Director of Mississippi Power from 2001 to 2003.
G. Edison Holland, Jr.
Executive Vice President, General Counsel, and Secretary
Age 55
Elected in 2001. Executive Vice President and General Counsel since 2001.
C. Alan Martin
President and Chief Executive Officer of SCS
Age 59
Elected in 2008. President and Chief Executive Officer of SCS since February 1, 2008. Previously served as Executive Vice President of the Customer Service Organization at Alabama Power from May 2001 through January 2008.
Charles D. McCrary
Executive Vice President
Age 56
Elected in 1998. Executive Vice President of Southern Company since February 2002; President, Chief Executive Officer, and Director of Alabama Power since October 2001.
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J. Barnie Beasley
President and Chief Executive Officer of Southern Nuclear
Age 56
Elected in 2004. President and Chief Executive Officer of Southern Nuclear since September 2004. Previously served as Executive Vice President of Southern Nuclear from January 2004 to September 2004; and Vice President from July 1998 through December 2003.
The officers of Southern Company were elected for a term running from the first meeting of the directors following the last annual meeting (May 23, 2007) for one year until the first board meeting after the next annual meeting or until their successors are elected and have qualified, except for Mr. Martin whose election was effective on February 1, 2008.
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EXECUTIVE OFFICERS OF ALABAMA POWER
(Identification of executive officers of Alabama Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2007.
Charles D. McCrary
President, Chief Executive Officer, and Director
Age 56
Elected in 2001. President, Chief Executive Officer, and Director since October 2001; Executive Vice President of Southern Company since February 2002.
Art P. Beattie
Executive Vice President, Chief Financial Officer, and Treasurer
Age 53
Elected in 2004. Executive Vice President, Chief Financial Officer, and Treasurer since February 2005. Previously served as Vice President and Comptroller of Alabama Power from 1998 through January 2005.
Mark A. Crosswhite
Executive Vice President
Age 45
Elected in 2008. Executive Vice President of External Affairs since February 1, 2008. Previously served as Senior Vice President and Counsel of Alabama Power from July 2006 through January 2008; Senior Vice President, General Counsel, and Assistant Secretary of Southern Power from March 2004 through January 2005; and Vice President of SCS from March 2004 through January 2008. Prior to March 2004, Mr. Crosswhite was a partner at the law firm of Balch & Bingham LLP.
Steven R. Spencer
Executive Vice President
Age 52
Elected in 2001. Executive Vice President of the Customer Service Organization since February 1, 2008. Previously served as Executive Vice President of External Affairs from 2001 through January 2008.
Jerry L. Stewart
Senior Vice President
Age 58
Elected in 1999. Senior Vice President of Fossil and Hydro Generation since 1999.
The officers of Alabama Power were elected for a term running from the last annual organizational meeting of the directors (July 27, 2007) for one year until the next annual meeting or until their successors are elected and have qualified, except for Mr. Crosswhite whose election was effective February 1, 2008.
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EXECUTIVE OFFICERS OF GEORGIA POWER
(Identification of executive officers of Georgia Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2007.
Michael D. Garrett
President, Chief Executive Officer, and Director
Age 58
Elected in 2003. President, Chief Executive Officer, and Director of Georgia Power since April 2004. Previously served as President and Director of Georgia Power from January 2004 to April 2004; President, Chief Executive Officer, and Director of Mississippi Power from May 2001 through December 2003.
Mickey A. Brown
Executive Vice President
Age 60
Elected in 2001. Executive Vice President of the Customer Service Organization since January 2005. Previously served as Senior Vice President of Distribution from May 2001 through December 2004.
Cliff S. Thrasher
Executive Vice President, Chief Financial Officer, and Treasurer
Age 57
Elected in 2005. Executive Vice President, Chief Financial Officer, and Treasurer since March 2005. Previously served as Senior Vice President, Comptroller, and Chief Financial Officer of Southern Power from November 2002 to March 2005 and Vice President of SCS from June 2002 to March 2005.
Christopher C. Womack
Executive Vice President
Age 49
Elected in 2001. Executive Vice President of External Affairs since March 2006. Previously served as Senior Vice President of Fossil and Hydro Generation and Senior Production Officer from December 2001 to February 2006.
Judy M. Anderson
Senior Vice President
Age 59
Elected in 2001. Senior Vice President of Charitable Giving since 2001.
Douglas E. Jones
Senior Vice President
Age 49
Elected in 2005. Senior Vice President of Fossil and Hydro Generation since March 2006. Previously served as Senior Vice President of Customer Service and Sales from January 2005 to February 2006; Executive Vice President of Southern Power from January 2004 to January 2005; Senior Vice President of SCS from December 2001 to January 2004.
James H. Miller, III
Senior Vice President and General Counsel
Age 58
Elected in 2004. Senior Vice President and General Counsel since March 2004. Previously served as Vice President and Associate General Counsel for SCS and Senior Vice President, General Counsel, and Assistant Secretary of Southern Power from August 2001 through February 2004.
Each of the above is currently an executive officer of Georgia Power, serving a term running from the last annual organizational meeting of the directors (May 16, 2007) for one year until the next annual meeting or until their successors are elected and qualified.
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EXECUTIVE OFFICERS OF MISSISSIPPI POWER
(Identification of executive officers of Mississippi Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2007.
Anthony J. Topazi
President, Chief Executive Officer, and Director
Age 57
Elected in 2003. President, Chief Executive Officer, and Director since January 1, 2004. Previously served as Executive Vice President of Southern Company Generation and Energy Marketing from November 2000 to December 2003; and Senior Vice President of Southern Power from November 2002 to December 2003.
John W. Atherton
Vice President
Age 47
Elected in 2004. Vice President of External Affairs since January 2005. Previously served as the Director of Economic Development from September 2003 to January 2005; and Manager, Sales and Marketing Services from April 2002 to August 2003.
Kimberly D. Flowers
Vice President
Age 44
Elected in 2005. Vice President and Senior Production Officer since March 2005. Previously served as Plant Manager, Plant Bowen, Georgia Power from November 2000 until March 2005.
Donald R. Horsley
Vice President
Age 53
Elected in 2006. Vice President of Customer Services and Retail Marketing since April 2006. Previously served as Vice President of Transmission at Alabama Power from March 2005 to March 2006 and Manager, Transmission Lines at Alabama Power from February 2001 to March 2005.
Frances V. Turnage
Vice President, Treasurer, and
Chief Financial Officer
Age 59
Elected in 2005. Vice President, Treasurer, and Chief Financial Officer since March 2005. Previously served as Comptroller from 1993 to March 2005.
The officers of Mississippi Power were elected for a term running from the last annual organizational meeting of the directors (April 11, 2007) for one year until the next annual meeting or until their successors are elected and have qualified.
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PART II
Item 5.
Item 5.
MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
(a)(1) The common stock of Southern Company is listed and traded on the New York Stock Exchange. The common stock is also traded on regional exchanges across the United States. The high and low stock prices for each quarter of the past two years were as follows:
There is no market for the other registrants’ common stock, all of which is owned by Southern Company.
(a)(2) Number of Southern Company’s common stockholders of record at December 31, 2007: 102,903
Each of the other registrants have one common stockholder, Southern Company.
(a)(3) Dividends on each registrant’s common stock are payable at the discretion of their respective board of directors. The dividends on common stock declared by Southern Company and the traditional operating companies to their stockholder(s) for the past two years were as follows:
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In 2006 and 2007, Southern Power paid dividends to Southern Company as follows:
The dividend paid per share of Southern Company’s common stock was 37.25¢ in the first quarter of 2006 and 38.75¢ for the remaining quarters of 2006 and the first quarter of 2007. For the second, third, and fourth quarters of 2007, the dividend paid per share of Southern Company’s common stock was 40.25¢.
The traditional operating companies and Southern Power can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
Southern Power’s credit facility contains potential limitations on the payment of common stock dividends. At December 31, 2007, Southern Power was in compliance with the conditions of this credit facility and thus had no restrictions on its ability to pay common stock dividends. See Note 8 to the financial statements of Southern Company under “Common Stock Dividend Restrictions” and Note 6 to the financial statements of Southern Power under “Dividend Restrictions” in Item 8 herein for additional information regarding these restrictions.
(a)(4) Securities authorized for issuance under equity compensation plans.
See Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters under the heading “Equity Compensation Plan Information” herein.
(b) Use of Proceeds
Not applicable.
(c) Issuer Purchases of Equity Securities
None.
Item 6.
Item 6. SELECTED FINANCIAL DATA
Southern Company. See “SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA,” contained herein at pages II-97 and II-98.
Alabama Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-159 and II-160.
Georgia Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-225 and II-226.
Gulf Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-282 and II-283.
Mississippi Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-343 and II-344.
Southern Power. See “SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA,” contained herein at page II-382.
Item 7.
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-12 through II-45.
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Alabama Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-102 through II-122.
Georgia Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-164 through II-185.
Gulf Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-230 through II-250.
Mississippi Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-287 through II-309.
Southern Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-348 through II-364.
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See MANAGEMENT’S DISCUSSION AND ANALYSIS - FINANCIAL CONDITION AND LIQUIDITY - “Market Price Risk” of each of the registrants in Item 7 herein and Note 1 of each of the registrant’s financial statements under “Financial Instruments” in Item 8
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO 2007 FINANCIAL STATEMENTS
II-4
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
II-5
Item 9A.
Item 9A. CONTROLS AND PROCEDURES
Disclosure Controls And Procedures.
As of the end of the period covered by this annual report, Southern Company conducted an evaluation under the supervision and with the participation of Southern Company’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934). Based upon this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective in alerting them in a timely manner to material information relating to Southern Company (including its consolidated subsidiaries) required to be included in periodic filings with the SEC.
Internal Control Over Financial Reporting.
(a) Management’s Annual Report on Internal Control Over Financial Reporting.
Southern Company’s Management’s Report on Internal Control Over Financial Reporting is included on page II-9 of this Form 10-K.
(b) Attestation Report of the Registered Public Accounting Firm.
The report of Deloitte & Touche LLP, Southern Company’s independent registered public accounting firm, regarding Southern Company’s internal control over financial reporting is included on page II-10 of this Form 10-K.
(c) Changes in internal controls.
There have been no changes in Southern Company’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the fourth quarter 2007 that have materially affected or are reasonably likely to materially affect Southern Company’s internal control over financial reporting.
Item 9A(T). CONTROLS AND PROCEDURES
Disclosure Controls And Procedures.
As of the end of the period covered by this annual report, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power conducted separate evaluations under the supervision and with the participation of each company’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective in alerting them in a timely manner to material information relating to their company (including its consolidated subsidiaries, if any) required to be included in periodic filings with the SEC.
Internal Control Over Financial Reporting.
(a) Management’s Annual Report on Internal Control Over Financial Reporting.
Alabama Power’s Management’s Report on Internal Control Over Financial Reporting is included on page II-100 of this Form 10-K.
Georgia Power’s Management’s Report on Internal Control Over Financial Reporting is included on page II-162 of this Form 10-K.
Gulf Power’s Management’s Report on Internal Control Over Financial Reporting is included on page II-228 of this Form 10-K.
II-6
Mississippi Power’s Management’s Report on Internal Control Over Financial Reporting is included on page II-285 of this Form 10-K.
Southern Power’s Management’s Report on Internal Control Over Financial Reporting is included on page II-346 of this Form 10-K.
(b) Changes in internal controls.
There have been no changes in Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the fourth quarter 2007 that have materially affected or are reasonably likely to materially affect Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting.
Item 9B.
Item 9B. OTHER INFORMATION
None.
II-7
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
II-8
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Southern Company and Subsidiary Companies 2007 Annual Report
Southern Company’s management 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 Southern Company’s internal control over financial reporting was conducted based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Southern Company’s internal control over financial reporting was effective as of December 31, 2007.
Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of Southern Company’s financial statements, has issued an attestation report on the effectiveness of Southern Company’s internal control over financial reporting as of December 31, 2007. Deloitte & Touche LLP’s report on Southern Company’s internal control over financial reporting is included herein.
/s/ David M. Ratcliffe
David M. Ratcliffe
Chairman, President, and Chief Executive Officer
/s/ W. Paul Bowers
W. Paul Bowers
Executive Vice President and Chief Financial Officer
February 25, 2008
II-9
Internal Control Over Financial Reporting
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Southern Company
We have audited the internal control over financial reporting of Southern Company and Subsidiary Companies (the “Company”) as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting (page II-9). Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2007 of the Company and our report dated February 25, 2008 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding changes in the method of accounting for uncertainty in income taxes and the method of accounting for the impact of changes in the timing of income tax cash flows generated by leveraged leases in 2007 and a change in the method of accounting for the funded status of defined benefit pension and other postretirement plans in 2006.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 25, 2008
II-10
Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Southern Company
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Southern Company and Subsidiary Companies (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of income, comprehensive income, common stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 consolidated financial statements (pages II-46 to II-95) present fairly, in all material respects, the financial position of Southern Company and Subsidiary Companies at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Notes 3 and 5 to the financial statements, in 2007 the Company changed its method of accounting for uncertainty in income taxes and its method of accounting for the impact of changes in the timing of income tax cash flows generated by leveraged leases. As discussed in Note 2 to the financial statements, in 2006 the Company changed its method of accounting for the funded status of defined benefit pension and other postretirement plans.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2008 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 25, 2008
II-11
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company and Subsidiary Companies 2007 Annual Report
OVERVIEW
Business Activities
The primary business of Southern Company (the Company) is electricity sales in the Southeast by the traditional operating companies - Alabama Power, Georgia Power, Gulf Power, and Mississippi Power - and Southern Power. The four traditional operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, and manages generation assets and sells electricity at market-based rates in the wholesale market.
Many factors affect the opportunities, challenges, and risks of Southern Company’s electricity business. These factors include the traditional operating companies’ ability to maintain a stable regulatory environment, to achieve energy sales growth, and to effectively manage and secure timely recovery of rising costs. Each of the traditional operating companies has various regulatory mechanisms that operate to address cost recovery. Since 2005, the traditional operating companies have completed a number of regulatory proceedings that provide for the timely recovery of costs. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future.
Another major factor is the profitability of the competitive market-based wholesale generating business and federal regulatory policy, which may impact Southern Company’s level of participation in this market. Southern Power continues to execute its regional strategy through a combination of acquiring and constructing new power plants and by entering into power purchase agreements (PPAs) with investor owned utilities, independent power producers, municipalities, and electric cooperatives. The Company continues to face regulatory challenges related to transmission and market power issues at the national level.
Southern Company’s other business activities include leveraged lease projects, telecommunications, energy-related services, and an investment in a synthetic fuel producing entity which claimed federal income tax credits designed to offset its operating losses. The availability of synthetic fuel tax credits and the Company’s investment in these activities ended on December 31, 2007. Management continues to evaluate the contribution of each of these remaining activities to total shareholder return and may pursue acquisitions and dispositions accordingly.
Key Performance Indicators
In striving to maximize shareholder value while providing cost-effective energy to more than four million customers, Southern Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and earnings per share (EPS), excluding earnings from synthetic fuel investments. Southern Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company’s results.
Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. The fossil/hydro 2007 Peak Season EFOR of 1.60% was better than the target. The nuclear generating fleet also uses Peak Season EFOR as an indicator of availability and efficient generation fleet operations during the peak season. The nuclear 2007 Peak Season EFOR of 0.94% was also better than target. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected capital expenditures. The performance for 2007 was better than target for these reliability measures.
II-12
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2007 Annual Report
Southern Company’s synthetic fuel investments have generated tax credits as a result of synthetic fuel production. Due to higher oil prices in 2006 and 2007, these tax credits were partially phased out and one synthetic fuel investment was terminated in 2006. These tax credits were no longer available after December 31, 2007. Southern Company management uses EPS, excluding earnings from synthetic fuel investments, to evaluate the performance of Southern Company’s ongoing business activities. Southern Company believes the presentation of earnings and EPS excluding the results of the synthetic fuel investments also is useful for investors because it provides investors with additional information for purposes of comparing Southern Company’s performance for such periods. The presentation of this additional information is not meant to be considered a substitute for financial measures prepared in accordance with generally accepted accounting principles.
Southern Company’s 2007 results compared with its targets for some of these key indicators are reflected in the following chart:
See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The financial performance achieved in 2007 reflects the continued emphasis that management places on these indicators as well as the commitment shown by employees in achieving or exceeding management’s expectations.
Earnings
Southern Company’s net income was $1.73 billion in 2007, an increase of 10.2% from the prior year. The higher earnings compared with the prior year were primarily the result of a warm summer and state regulatory actions. These positive factors were offset in part by higher non-fuel operations and maintenance expenses, higher interest expense, and higher asset depreciation primarily associated with increased investment in environmental equipment at generating plants and transmission and distribution related to maintaining reliability. Net income was $1.57 billion in 2006 and $1.59 billion in 2005, reflecting a 1.1% decrease and a 3.8% increase over the prior year, respectively. Basic EPS was $2.29 in 2007, $2.12 in 2006, and $2.14 in 2005. Diluted EPS, which factors in additional shares related to stock options, was $2.28 for 2007, $2.10 for 2006, and $2.13 for 2005.
Dividends
Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $1.595 in 2007, $1.535 in 2006, and $1.475 in 2005. In January 2008, Southern Company declared a quarterly dividend of 40.25 cents per share. This is the 241st consecutive quarter that Southern Company has paid a dividend equal to or higher than the previous quarter. The Company targets a dividend payout ratio of approximately 70% of net income, excluding earnings from synthetic fuel investments. For 2007, the actual payout ratio was 72%, excluding earnings from synthetic fuel investments, and 69.5% overall.
RESULTS OF OPERATIONS
Electricity Business
Southern Company’s electric utilities generate and sell electricity to retail and wholesale customers in the Southeast.
II-13
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2007 Annual Report
A condensed income statement for the electricity business follows:
Electric Operating Revenues
Details of electric operating revenues were as follows:
Retail revenues increased $838 million, $636 million, and $1.4 billion in 2007, 2006, and 2005, respectively. The significant factors driving these changes are shown in the preceding table. The increase in rates and pricing in 2007 was primarily due to Alabama Power’s increase under its Rate Stabilization and Equalization Plan (Rate RSE), as ordered by the Alabama Public Service Commission (PSC). See Note 3 to the financial statements under “Alabama Power Retail Regulatory Matters” for additional information. Partially offsetting the 2007 increase was a decrease in contributions from market-based rates to large commercial and industrial customers at Georgia Power. The 2006 increase in rates and pricing when compared to the prior year was not material. The increase in rates and pricing in 2005 was primarily due to approval by the Georgia PSC of a retail base rate increase at Georgia Power. See “Energy Sales” below for a discussion of changes in the volume of energy sold, including changes related to sales growth and weather.
Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally
II-14
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2007 Annual Report
equal fuel expenses, including the fuel component of purchased power, and do not affect net income. The traditional operating companies may also have one or more regulatory mechanisms to recover other costs such as environmental, storm damage, new plants, and PPAs.
Wholesale revenues consist of PPAs with investor-owned utilities and electric cooperatives, short-term opportunity sales, and unit power sales contracts. Southern Company’s average wholesale contract extends more than 11 years and, as a result, the Company has significantly limited its remarketing risk.
In 2007, wholesale revenues increased $166 million primarily as a result of a 9.5% increase in the average cost of fuel per net kilowatt-hour (KWH) generated. Excluding fuel, wholesale revenues were flat when compared to the prior year.
In 2006, wholesale revenues increased $155 million primarily as a result of a 10.5% increase in the average cost of fuel per net KWH generated, as well as revenues resulting from new PPAs in 2006. In addition, Southern Company assumed four PPAs through the acquisitions of Plants DeSoto and Rowan in June and September 2006, respectively. The 2006 increase was partially offset by a decrease in short-term opportunity sales.
In 2005, wholesale revenues increased $326 million primarily due to a 26.5% increase in the average cost of fuel per net KWH generated. In addition, Southern Company entered into new PPAs with 30 electric membership cooperatives (EMCs) and Flint EMC, both beginning in January 2005, and assumed two PPAs in June 2005 in connection with the acquisition of Plant Oleander.
Short-term opportunity sales are made at market-based rates that generally provide a margin above the Company’s variable cost to produce the energy. Revenues associated with PPAs and opportunity sales were as follows:
Capacity revenues under unit power sales contracts, principally sales to Florida utilities, reflect the recovery of fixed costs and a return on investment. Unit power KWH sales decreased 0.8% in 2007 and increased 0.2% and 1.7% in 2006 and 2005, respectively. Fluctuations in oil and natural gas prices, which are the primary fuel sources for unit power sales customers, influence changes in these sales. However, because the energy is generally sold at variable cost, these fluctuations have a minimal effect on earnings. The capacity and energy components of the unit power sales contracts were as follows:
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2007 and the percent change by year were as follows:
II-15
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2007 Annual Report
Retail energy sales in 2007 increased 2.3 billion KWHs as a result of 1.3% customer growth and favorable weather in 2007 when compared to 2006. The 2007 decrease in industrial sales primarily resulted from reduced demand and closures within the textile industry, as well as decreased demand in the primary metals sector and the stone, clay, and glass sector. Retail energy sales in 2006 increased 2.3 billion KWHs as a result of customer growth of 1.7%, sustained economic growth primarily in the residential and commercial customer classes, and favorable weather in 2006 when compared to 2005. Retail energy sales in 2005 increased 1.9 billion KWHs as a result of sustained economic growth and customer growth of 1.2%. Hurricane Katrina dampened customer growth from previous years and was the primary contributor to the decrease in industrial sales in 2005. In addition, in 2005, some Georgia Power industrial customers were reclassified from industrial to commercial to be consistent with the rate structure approved by the Georgia PSC resulting in higher commercial sales and lower industrial sales in 2005 when compared with 2004.
Wholesale energy sales increased by 2.3 billion KWHs, 1.4 billion KWHs, and 2.5 billion KWHs in 2007, 2006, and 2005, respectively. The increase in wholesale energy sales in 2007 was primarily related to new PPAs acquired by Southern Company through the acquisition of Plant Rowan in September 2006, as well as new contracts with EnergyUnited Electric Membership Corporation that commenced in September 2006 and January 2007. An increase in KWH sales under existing PPAs also contributed to the 2007 increase. The increases in wholesale energy sales in 2006 and 2005 were related primarily to the new PPAs discussed previously under “Electric Operating Revenues.”
Fuel and Purchased Power Expenses
Fuel costs constitute the single largest expense for the electric utilities. 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 electric utilities purchase a portion of their electricity needs from the wholesale market. Details of Southern Company’s electricity generated and purchased were as follows:
II-16
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2007 Annual Report
In 2007, fuel and purchased power expenses were $6.4 billion, an increase of $673 million or 11.8% above 2006 costs. This increase was primarily the result of a $543 million net increase in the average cost of fuel and purchased power partially resulting from a 51.4% decrease in hydro generation as a result of a severe drought. Also contributing to this increase was a $130 million increase related to an increase in net KWHs generated and purchased.
Fuel and purchased power expenses were $5.7 billion in 2006, an increase of $467 million or 8.9% above the prior year costs. This increase was primarily the result of a $367 million net increase in the average cost of fuel and purchased power and a $100 million increase related to an increase in net KWHs generated and purchased.
In 2005, fuel and purchased power expenses were $5.2 billion, an increase of $1.2 billion or 29.1% above 2004 costs. This increase was the result of a $1.3 billion net increase in the average cost of fuel and purchased power, partially offset by $67 million related to a decrease in net KWHs generated and purchased.
While there has been a significant upward trend in the cost of coal and natural gas since 2003, prices moderated somewhat in 2006 and 2007. Coal prices have been influenced by a worldwide increase in demand from developing countries, as well as increases in mining and fuel transportation costs. While demand for natural gas in the United States continued to increase in 2007, natural gas supplies have also risen due to increased production and higher storage levels. During 2007, uranium prices were volatile and increased over the course of the year due to increasing long-term demand with primary production levels at approximately 55% to 60% of demand. Secondary supplies and inventories were sufficient to fill the primary production shortfall.
Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the traditional operating companies’ fuel cost recovery provisions. Likewise, Southern Power’s PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel.
Other Operations and Maintenance Expenses
Other operations and maintenance expenses were $3.5 billion, $3.3 billion, and $3.2 billion, increasing $183 million, $70 million, and $215 million in 2007, 2006, and 2005, respectively. Discussion of significant variances for components of other operations and maintenance expenses follows.
Other production expenses at fossil, hydro, and nuclear plants increased $128 million, $3 million, and $58 million in 2007, 2006, and 2005, respectively. Production expenses fluctuate from year to year due to variations in outage schedules and normal increases in costs. Other production expenses increased in 2007 primarily due to a $40 million increase related to expenses incurred for maintenance outages at generating units and a $29 million increase related to new facilities, mainly costs associated with the write-off of Southern Power’s integrated coal gasification combined cycle (IGCC) project and the acquisitions of Plants DeSoto and Rowan by Southern Power in June and September 2006, respectively. A $25 million increase related to labor and materials expenses and a $22 million increase in nuclear refueling costs also contributed to the 2007 increase. See FUTURE EARNINGS POTENTIAL - “Construction Projects - Integrated Coal Gasification Combined Cycle” herein for additional information regarding the write-off of Southern Power’s IGCC project and Note 1 to the financial statements under “Property, Plant, and Equipment” for additional information regarding the amortization of nuclear refueling costs. The 2006 increase in other production expenses when compared to the prior year was not material. Other production expenses increased in 2005 due to a $50 million increase related primarily to expenses incurred for maintenance outages at generating units.
Administrative and general expenses increased $28 million, $29 million, and $73 million in 2007, 2006, and 2005, respectively. Administrative and general expenses increased in 2007 primarily as a result of a $16 million increase in legal costs and expenses associated with an increase in employees. Also contributing to the 2007 increase was a
II-17
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2007 Annual Report
$14 million increase in accrued expenses for the litigation and workers’ compensation reserve, partially offset by an $8 million decrease in property damage expense. Administrative and general expenses increased in 2006 primarily as a result of a $17 million increase in salaries and wages and a $24 million increase in pension expense, partially offset by a $16 million reduction in medical expenses. Administrative and general expenses increased in 2005 primarily related to a $33 million increase in employee benefits; a $22 million increase in Sarbanes-Oxley Act compliance costs, legal costs, and other corporate expenses; and a $9 million increase in property damage expense.
Transmission and distribution expenses increased $21 million, $30 million, and $60 million in 2007, 2006, and 2005, respectively. Transmission and distribution expenses fluctuate from year to year due to variations in maintenance schedules and normal increases in costs. Transmission and distribution expenses increased in 2007 primarily as a result of increases in labor and materials costs and maintenance associated with additional investment to meet customer growth. Transmission and distribution expenses increased in 2006 primarily due to expenses associated with recovery of prior year storm costs through natural disaster recovery clauses and maintenance associated with additional investment in distribution to meet customer growth. Transmission and distribution expenses increased in 2005 primarily as a result of $48 million of expenses recorded by Alabama Power in accordance with an accounting order approved by the Alabama PSC primarily to offset the costs of Hurricane Ivan and restore the natural disaster reserve. In accordance with the accounting order, Alabama Power also returned certain regulatory liabilities related to deferred income taxes to its retail customers; therefore, the combined effect of the accounting order had no impact on net income. See Note 3 to the financial statements under “Storm Damage Cost Recovery” for additional information.
Depreciation and Amortization
Depreciation and amortization increased $51 million in 2007 primarily as a result of additional investments in environmental equipment at generating plants and transmission and distribution projects mainly at Alabama Power and Georgia Power and an increase in the amortization expense of a regulatory liability recorded in 2003 in connection with the Mississippi PSC’s accounting order on Plant Daniel capacity. Partially offsetting the 2007 increase was a reduction in amortization expense due to a Georgia Power regulatory liability related to the levelization of certain purchased power capacity costs as ordered by the Georgia PSC under the terms of the retail rate order effective January 1, 2005. See Note 1 to the financial statements under “Depreciation and Amortization” for additional information.
Depreciation and amortization increased $27 million in 2006 primarily as a result of the acquisitions of Plants DeSoto, Rowan, and Oleander in June 2006, September 2006, and June 2005, respectively, and an increase in the amortization expense of the Mississippi Power regulatory liability related to Plant Daniel capacity. An increase in depreciation rates at Southern Power associated with adoption of a new depreciation study also contributed to the 2006 increase. Partially offsetting the 2006 increase was a reduction in the amortization expense of a Georgia Power regulatory liability related to the levelization of certain purchased power capacity costs.
Depreciation and amortization increased $229 million in 2005 primarily as a result of additional plant in service and from the expiration in 2004 of certain provisions related to the amortization of regulatory liabilities associated with purchased power capacity costs in Georgia Power’s retail rate plan for the three years ended December 31, 2004.
Taxes Other than Income Taxes
Taxes other than income taxes increased $23 million in 2007 primarily as a result of increases in franchise and municipal gross receipts taxes associated with increases in revenues from energy sales, partially offset by a decrease in property taxes resulting from the resolution of a dispute with Monroe County, Georgia. Taxes other than income taxes increased $39 million in 2006 primarily as a result of increases in franchise and municipal gross receipts taxes associated with increases in revenues from energy sales, as well as increases in property taxes associated with
II-18
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2007 Annual Report
additional plant in service. Taxes other than income taxes increased $52 million in 2005 primarily as a result of increases in franchise and municipal gross receipts taxes associated with increases in revenues from energy sales.
Other Income, Net
Other income, net increased $68 million in 2007 primarily as a result of a $56 million increase in allowance for equity funds used during construction related to additional investments in environmental equipment at generating plants and transmission and distribution projects mainly at Alabama Power and Georgia Power. The 2006 decrease in other income, net when compared to the prior year was not material. Other income, net increased $38 million in 2005 primarily as a result of a $19 million reduction largely related to the disallowance of certain Plant McIntosh costs by the Georgia PSC in 2004, a $10 million increase related primarily to changes in the value of derivative transactions, and a $6 million increase in interest income.
Interest Expense and Dividends
Total interest charges and other financing costs increased by $61 million in 2007 primarily as a result of a $72 million increase associated with $1.2 billion in additional debt and preference stock outstanding at December 31, 2007 compared to December 31, 2006 and higher interest rates associated with the issuance of new long-term debt. Also contributing to the 2007 increase was $7 million related to higher average interest rates on existing variable rate debt and $19 million in other interest costs. These increases were partially offset by $38 million more capitalized interest as compared to 2006.
Total interest charges and other financing costs increased by $75 million in 2006 primarily due to a $78 million increase associated with $708 million in additional debt outstanding at December 31, 2006 compared to December 31, 2005 and higher interest rates associated with the issuance of new long-term debt. Also contributing to the 2006 increase was $7 million associated with higher average interest rates on existing variable rate debt, partially offset by $6 million more capitalized interest associated with construction projects and $3 million in lower other interest costs.
Total interest charges and other financing costs increased by $62 million in 2005 associated with an additional $863 million in debt outstanding at December 31, 2005 as compared to December 31, 2004 and an increase in average interest rates on variable rate debt. Variable rates on pollution control bonds are highly correlated with the Securities Industry and Financial Markets Association Municipal Swap Index, which averaged 2.5% in 2005 and 1.2% in 2004. Variable rates on commercial paper and senior notes are highly correlated with the one-month London Interbank Offer Rate, which averaged 3.4% in 2005 and 1.5% in 2004. An additional $17 million increase in 2005 was the result of a lower percentage of interest costs capitalized as construction projects reached completion.
Income Taxes
Income taxes were relatively flat in 2007 as higher pre-tax earnings were largely offset due to a deduction for a Georgia Power land donation, the tax benefit associated with an increase in allowance for equity funds used during construction, and an increase in the Internal Revenue Code of 1986, as amended (Internal Revenue Code), Section 199 production activities deduction. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.
Income taxes increased $50 million in 2006 primarily due to higher pre-tax earnings and the impact of the accounting order approved by the Alabama PSC discussed previously under “Other Operations and Maintenance Expenses.” See Note 3 to the financial statements under “Storm Damage Cost Recovery” for additional information.
II-19
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2007 Annual Report
Income taxes increased $24 million in 2005 primarily as a result of higher pre-tax earnings, partially offset by the impact of the accounting order approved by the Alabama PSC discussed above.
Other Business Activities
Southern Company’s other business activities include the parent company (which does not allocate operating expenses to business units), investments in leveraged lease and synthetic fuel projects, telecommunications, and energy-related services. These businesses are classified in general categories and may comprise one or more of the following subsidiaries: Southern Company Holdings invests in various energy-related projects, including leveraged lease and synthetic fuel projects that receive tax benefits, which contribute significantly to the economic results of these investments; SouthernLINC Wireless provides digital wireless communications to the traditional operating companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Company’s investment in the synthetic fuel projects ended at December 31, 2007. A condensed income statement for Southern Company’s other business activities follows:
Operating Revenues
Southern Company’s non-electric operating revenues from these other businesses decreased $55 million in 2007 primarily as a result of a $13 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to increased competition in the industry. Also contributing to the 2007 decrease was a $14 million decrease in fuel procurement service revenues following a contract termination and an $11 million decrease in revenues from Southern Company’s energy-related services business. The $8 million decrease in 2006 primarily resulted from a $21 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and lower equipment and accessory sales. The 2006 decrease was partially offset by a $12 million increase in fuel procurement service revenues. Higher production and increased fees in the synthetic fuel business contributed to the $12 million increase in 2005.
Other Operations and Maintenance Expenses
Other operations and maintenance expenses for these other businesses decreased $29 million in 2007 primarily as a result of $11 million of lower production expenses related to the termination of Southern Company’s membership interest in one of the synthetic fuel entities and $8 million attributed to the wind-down of one of the Company’s
II-20
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2007 Annual Report
energy-related services businesses. Other operations and maintenance expenses decreased $59 million in 2006 primarily as a result of $32 million of lower production expenses related to the termination of Southern Company’s membership interest in one of the synthetic fuel entities, $13 million attributed to the wind-down of one of the Company’s energy-related services businesses, and $7 million of lower expenses resulting from the March 2006 sale of a subsidiary that provided rail car maintenance services. Other operations and maintenance expenses increased by $12 million in 2005 primarily as a result of $9 million of higher losses for property damage, $2 million in higher network costs at SouthernLINC Wireless, and an $11 million increase in shared service expenses, partially offset by the $12.5 million bad debt reserve in 2004 related to additional federal income taxes and interest Southern Company paid on behalf of Mirant Corporation (Mirant). See FUTURE EARNINGS POTENTIAL - “Mirant Matters” herein and Note 3 to the financial statements under “Mirant Matters - Mirant Bankruptcy” for additional information.
Equity in Losses of Unconsolidated Subsidiaries
Southern Company made investments in two synthetic fuel production facilities that generated operating losses. These investments allowed Southern Company to claim federal income tax credits that offset these operating losses and made the projects profitable. The 2007 decrease in equity in losses of unconsolidated subsidiaries was the result of terminating Southern Company’s membership interest in one of the synthetic fuel entities which reduced the amount of the Company’s share of the losses and, therefore, the funding obligation for the year. Also contributing to the 2007 decrease were adjustments related the phase-out of the related federal income tax credits, partially offset by higher operating expenses due to idled production in 2006 and decreased production in 2007 in anticipation of exiting the business. The 2006 decrease in equity in losses of unconsolidated subsidiaries was the result of terminating Southern Company’s membership interest in one of the synthetic fuel entities which reduced the amount of the Company’s share of the losses and, therefore, the funding obligation for the year. The 2006 decrease also resulted from lower operating expenses while the production facilities at the other synthetic fuel entity were idled from May to September 2006 due to higher oil prices. The increase in equity in losses of unconsolidated subsidiaries in 2005 resulted from additional production expenses at the synthetic fuel production facilities. The net synthetic fuel tax credits resulting from these investments totaled $36 million in 2007, $65 million in 2006, and $177 million in 2005.
Leveraged Lease Income
Southern Company has several leveraged lease agreements which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Leveraged lease income decreased $29 million in 2007 as a result of the adoption of Financial Accounting Standards Board (FASB) Staff Position No. FAS 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction” (FSP 13-2), as well as an expected decline in leveraged lease income over the terms of the leases. See FUTURE EARNINGS POTENTIAL - “Income Tax Matters - Leveraged Lease Transactions” herein for further information. The 2006 and 2005 changes in leveraged lease income when compared to the prior year were not material.
Other Income, Net
Other income, net for these other businesses increased $73 million in 2007 primarily as a result of a $60 million increase related to changes in the value of derivative transactions in the synthetic fuel business and a $16 million increase related to the 2006 impairment of investments in the synthetic fuel entities, partially offset by the release of $6 million in certain contractual obligations associated with these investments in 2006. The $19 million decrease in other income, net in 2006 as compared with 2005 primarily resulted from a $25 million decrease related to changes in the value of derivative transactions in the synthetic fuel business and the previously mentioned impairment and
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release of contractual obligations. The 2005 decrease in other income, net when compared to the prior year was not material.
Interest Expense
Total interest charges and other financing costs for these other businesses decreased by $27 million in 2007 primarily as a result of $16 million of losses on debt that was reacquired in 2006. Also contributing to the 2007 decrease was $97 million less debt outstanding at December 31, 2007 compared to December 31, 2006, lower interest rates associated with the issuance of new long-term debt, and a $4 million decrease in other interest costs. Total interest charges and other financing costs increased by $48 million in 2006 primarily due to a $19 million increase associated with $149 million in additional debt outstanding at December 31, 2006 as compared to December 31, 2005 and higher interest rates associated with the issuance of new long-term debt. Also contributing to the increase were $12 million associated with higher average interest rates on existing variable rate debt, a $6 million loss on the early redemption of long-term debt payable to affiliated trusts in January 2006, and a $16 million loss on the repayment of long-term debt payable to affiliated trusts in December 2006. The 2006 increase was partially offset by $4 million in lower other interest costs. Interest expense increased by $18 million in 2005 associated with an additional $283 million in debt outstanding and a 164 basis point increase in average interest rates on variable rate debt.
Income Taxes
Income taxes for these other businesses increased $53 million in 2007 primarily as a result of a $30 million decrease in net synthetic fuel tax credits as a result of terminating Southern Company’s membership interest in one of the synthetic fuel entities in 2006 and increasing the synthetic fuel tax credit reserves due to an anticipated phase-out of synthetic fuel tax credits due to higher oil prices. The $136 million increase in income taxes in 2006 as compared with 2005 primarily resulted from a $111 million decrease in net synthetic fuel tax credits as a result of terminating Southern Company’s membership interest in one of the synthetic fuel entities, curtailing production at the other synthetic fuel entity from May to September 2006, and increasing the synthetic fuel tax credit reserves due to an anticipated phase-out of synthetic fuel tax credits due to higher oil prices. See Note 5 to the financial statements under “Effective Tax Rate” for further information. The 2005 decrease in income taxes when compared to the prior year was not material.
Effects of Inflation
The traditional operating companies and Southern Power are subject to rate regulation and party to long-term contracts that are generally based on the recovery of historical costs. When historical costs are included, or when inflation exceeds projected costs used in rate regulation or in market-based prices, the effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. In addition, the income tax laws are based on historical costs. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on Southern Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations such as long-term debt, preferred securities, preferred stock, and preference stock. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed in the traditional operating companies’ approved electric rates.
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FUTURE EARNINGS POTENTIAL
General
The four traditional operating companies operate as vertically integrated utilities providing electricity to customers within their service areas in the southeastern United States. Prices for electricity provided to retail customers are set by state PSCs under cost-based regulatory principles. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the Federal Energy Regulatory Commission (FERC). Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. Southern Power continues to focus on long-term capacity contracts, optimized by limited energy trading activities. See ACCOUNTING POLICIES - “Application of Critical Accounting Policies and Estimates - Electric Utility Regulation” herein and Note 3 to the financial statements 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 Southern Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Company’s primary business of selling electricity. These factors include the traditional operating companies’ ability to maintain a stable regulatory environment that continues to allow for the recovery of all prudently incurred costs during a time of increasing costs. Other major factors include the profitability of the competitive wholesale supply business and federal regulatory policy (including the FERC’s market-based rate proceeding), which may impact Southern Company’s level of participation in this market. Future earnings for the electricity business in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the service area. In addition, the level of future earnings for the wholesale supply business also depends on numerous factors including creditworthiness of customers, total generating capacity available in the Southeast, and the successful remarketing of capacity as current contracts expire.
Southern Company system generating capacity increased 163 megawatts due to Southern Power’s completion of Plant Oleander Unit 5 in December 2007. In general, Southern Company has constructed or acquired new generating capacity only after entering into long-term capacity contracts for the new facilities or to meet requirements of Southern Company’s regulated retail markets, both of which are optimized by limited energy trading activities.
To adapt to a less regulated, more competitive environment, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company.
Environmental Matters
Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. Some of the factors driving the potential for such an increase are higher commodity costs, market demand for labor, and scope additions and clarifications. The timing, specific requirements, and estimated costs could also change as environmental statutes and regulations are adopted or modified. See Note 3 to the financial statements under “Environmental Matters” for additional information.
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New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama after Alabama Power was dismissed from the original action. In these lawsuits, the EPA alleged that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The action against Georgia Power has been administratively closed since the spring of 2001, and the case has not been reopened.
In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving the alleged NSR violations at Plant Miller. The consent decree required Alabama Power to pay $100,000 to resolve the government’s claim for a civil penalty and to donate $4.9 million of sulfur dioxide emission allowances to a nonprofit charitable organization and formalized specific emissions reductions to be accomplished by Alabama Power, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in Alabama granted Alabama Power’s motion for summary judgment and entered final judgment in favor of Alabama Power on the EPA’s claims related to all of the remaining plants: Plants Barry, Gaston, Gorgas, and Greene County.
The plaintiffs appealed the district court’s decision to the U.S. Court of Appeals for the Eleventh Circuit, and the appeal was stayed by the Appeals Court pending the U.S. Supreme Court’s decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke Energy case in April 2007. On October 5, 2007, the U.S. District Court for the Northern District of Alabama issued an order in the Alabama Power case indicating a willingness to re-evaluate its previous decision in light of the Supreme Court’s Duke Energy opinion. On December 21, 2007, the Eleventh Circuit vacated the district court’s decision in the Alabama Power case and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court’s decision in the Duke Energy case. The final outcome of these matters cannot be determined at this time.
Southern Company believes that the traditional operating companies complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in either of these cases could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
The EPA has issued a series of proposed and final revisions to its NSR regulations under the Clean Air Act, many of which have been subject to legal challenges by environmental groups and states. In June 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s revisions to NSR regulations that were issued in December 2002 but vacated portions of those revisions addressing the exclusion of certain pollution control projects. These regulatory revisions have been adopted by each of the states within Southern Company’s service territory. In March 2006, the U.S. Court of Appeals for the District of Columbia Circuit also vacated an EPA rule which sought to clarify the scope of the existing routine maintenance, repair, and replacement exclusion. The EPA has also published proposed rules clarifying the test for determining when an emissions increase subject to the NSR permitting requirements has occurred. The impact of these proposed rules will depend on adoption of the final rules by the EPA and the individual state implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.
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Carbon Dioxide Litigation
In July 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005, and no decision has been issued. The ultimate outcome of these matters cannot be determined at this time.
Environmental Statutes and Regulations
General
Southern Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; and the Endangered Species Act. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2007, Southern Company had invested approximately $4.7 billion in capital projects to comply with these requirements, with annual totals of $1.5 billion, $661 million, and $423 million for 2007, 2006, and 2005, respectively. The Company expects that capital expenditures to assure compliance with existing and new statutes and regulations will be an additional $1.8 billion, $1.5 billion, and $0.6 billion for 2008, 2009, and 2010, respectively. The Company’s compliance strategy is impacted by changes to existing environmental laws, statutes, and regulations, the cost, availability, and existing inventory of emission allowances, and the Company’s fuel mix. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY - “Capital Requirements and Contractual Obligations” herein.
Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect Southern Company. New environmental legislation or regulations, or changes to existing statutes or regulations, could affect many areas of Southern Company’s operations; however, the full impact of any such changes cannot be determined at this time.
Air Quality
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for Southern Company. Through 2007, the Company had spent approximately $3.8 billion in reducing sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been announced and are currently being installed at several plants to further reduce SO2, NOx, and mercury emissions, maintain compliance with existing regulations, and meet new requirements.
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In 2004, the EPA designated nonattainment areas under an eight-hour ozone standard. Areas within Southern Company’s service area that were designated as nonattainment under the eight-hour ozone standard included Macon (Georgia), Jefferson and Shelby Counties, near and including Birmingham (Alabama), and a 20-county area within metropolitan Atlanta. The Macon area was redesignated by the EPA as an attainment area on September 19, 2007. The Birmingham area was redesignated to attainment by the EPA in June 2006, and the EPA subsequently approved a maintenance plan for the area to address future exceedances of the standard. In December 2006, the U.S. Court of Appeals for the District of Columbia Circuit vacated the first set of implementation rules adopted in 2004 and remanded the rules to the EPA for further refinement. On June 20, 2007, the EPA proposed additional revisions to the current eight-hour ozone standard which, if enacted, could result in designation of new nonattainment areas within Southern Company’s service territory. The EPA has requested comment and is expected to publish final revisions to the standard in 2008. The impact of this decision, if any, cannot be determined at this time and will depend on subsequent legal action and/or future nonattainment designations and state regulatory plans.
During 2005, the EPA’s fine particulate matter nonattainment designations became effective for several areas within Southern Company’s service area in Alabama and Georgia. State plans for addressing the nonattainment designations under the existing standard are required by April 2008 and could require further reductions in SO2 and NOx emissions from power plants. In September 2006, the EPA published a final rule which increased the stringency of the 24-hour average fine particulate matter air quality standard. In December 2007, state agencies recommended to the EPA that Jefferson County (Birmingham) and Etowah County (Gadsden) in Alabama and an area encompassing all or parts of 22 counties within metropolitan Atlanta in Georgia be designated as nonattainment for this standard. The EPA plans to designate nonattainment areas based on the new standard by December 2009. The ultimate outcome of this matter depends on the development and submittal of the required state plans and resolution of pending legal challenges and, therefore, cannot be determined at this time.
The EPA issued the final Clean Air Interstate Rule in March 2005. This cap-and-trade rule addresses power plant SO2 and NOx emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including each of the states within Southern Company’s service area, are subject to the requirements of the rule. The rule calls for additional reductions of NOx and/or SO2 to be achieved in two phases, 2009/2010 and 2015. States in the Southern Company service territory have completed plans to implement this program. These reductions will be accomplished by the installation of additional emission controls at Southern Company’s coal-fired facilities and/or by the purchase of emission allowances from a cap-and-trade program.
The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized in July 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves (1) the application of Best Available Retrofit Technology (BART) to certain sources built between 1962 and 1977 and (2) the application of any additional emissions reductions which may be deemed necessary for each designated area to achieve reasonable progress by 2018 toward the natural conditions goal. Thereafter, for each 10-year planning period, additional emissions reductions will be required to continue to demonstrate reasonable progress in each area during that period. For power plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for SO2 and NOx. Extensive studies were performed for each of the Company’s affected units to demonstrate that additional particulate matter controls are not necessary under BART. At the request of the State of Georgia, additional analyses were performed for certain units in Georgia to demonstrate that no additional SO2 controls were required. Additional analyses will be required for one of the Company’s plants in Florida. States are currently completing implementation plans that contain strategies for BART and any other measures required to achieve the first phase of reasonable progress.
The impacts of the eight-hour ozone and the fine particulate matter nonattainment designations and the Clean Air Visibility Rule on the Company will depend on the development and implementation of rules at the state level. For
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example, while it has implemented the Clean Air Interstate Rule, in June 2007 the State of Georgia approved a “multi-pollutant rule” that will require plant-specific emission controls on all but the smallest generating units in Georgia according to a schedule set forth in the rule. The rule is designed to ensure reductions in emissions of SO2, NOx, and mercury in Georgia. Therefore, the full effects of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO2 and NOx emission controls within the next several years to assure continued compliance with applicable air quality requirements.
In March 2005, the EPA published the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emission allowance trading market. The final Clean Air Mercury Rule was challenged in the U.S. Court of Appeals for the District of Columbia Circuit. The petitioners alleged that the EPA was not authorized to establish a cap-and-trade program for mercury emissions and instead the EPA must establish maximum achievable control technology standards for coal-fired electric utility steam generating units. On February 8, 2008, the court issued its ruling and vacated the Clean Air Mercury Rule. The Company’s overall environmental compliance strategy relies primarily on a combination of SO2 and NOx controls to reduce mercury emissions. Any significant changes in the strategy will depend on the outcome of any appeals and/or future federal and state rulemakings. Future rulemakings could require emission reductions more stringent than required by the Clean Air Mercury Rule.
Water Quality
In July 2004, the EPA published its final technology-based regulations under the Clean Water Act for the purpose of reducing impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures. The rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants. On January 25, 2007, the U.S. Court of Appeals for the Second Circuit overturned and remanded several provisions of the rule to the EPA for revisions. Among other things, the court rejected the EPA’s use of “cost-benefit” analysis and suggested some ways to incorporate cost considerations. The full impact of these regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.
Environmental Remediation
Southern Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and release of hazardous substances. Under these various laws and regulations, the traditional operating companies could incur substantial costs to clean up properties. The traditional operating companies conduct studies to determine the extent of any required cleanup and have recognized in their respective financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The traditional operating companies may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under “Environmental Matters - Environmental Remediation” for additional information.
Global Climate Issues
Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions continue to be considered in Congress. The ultimate outcome of these proposals cannot be determined at this time; however, mandatory restrictions on the Company’s greenhouse gas emissions could result in significant additional
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compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. The EPA is currently developing its response to this decision. Regulatory decisions that will follow from this response may have implications for both new and existing stationary sources, such as power plants. The ultimate outcome of these rulemaking activities cannot be determined at this time; however, as with the current legislative proposals, mandatory restrictions on the Company’s greenhouse gas emissions could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
In addition, some states are considering or have undertaken actions to regulate and reduce greenhouse gas emissions. For example, on July 13, 2007, the Governor of the State of Florida signed three executive orders addressing reduction of greenhouse gas emissions within the state, including statewide emission reduction targets beginning in 2017. Included in the orders is a directive to the Florida Secretary of Environmental Protection to develop rules adopting maximum allowable emissions levels of greenhouse gases for electric utilities, consistent with the statewide emission reduction targets, and a request to the Florida PSC to initiate rulemaking requiring utilities to produce at least 20% of their electricity from renewable sources. The impact of these orders on Southern Company will depend on the development, adoption, and implementation of any rules governing greenhouse gas emissions, and the ultimate outcome cannot be determined at this time.
International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. Current efforts focus on a potential successor to the Kyoto Protocol for the post 2008 through 2012 timeframe. The outcome and impact of the international negotiations cannot be determined at this time.
The Company continues to evaluate its future energy and emission profiles and is participating in voluntary programs to reduce greenhouse gas emissions and to help develop and advance technology to reduce emissions.
FERC Matters
Market-Based Rate Authority
Each of the traditional operating companies and Southern Power has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.
In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales by any subsidiary of Southern Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level.
In late June and July 2007, hearings were held in this proceeding and the presiding administrative law judge issued an initial decision on November 9, 2007 regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the traditional operating companies and Southern Power to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates, and could also result in refunds of up to $19.7
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million, plus interest. Southern Company and its subsidiaries believe that there is no meritorious basis for this proceeding and are vigorously defending themselves in this matter.
On June 21, 2007, the FERC issued its final rule regarding market-based rate authority. The FERC generally retained its current market-based rate standards. The impact of this order and its effect on the generation dominance proceeding cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet in its retail service territory is operated under the Intercompany Interchange Contract (IIC), as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies, Southern Power, and Southern Company Services, Inc. (SCS), as agent, under the terms of which the power pool of Southern Company is operated, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct.
In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms and Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. Southern Company filed with the FERC in November 2006 a compliance plan in connection with the order. On April 19, 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan is not expected to have a material impact on the Company’s financial statements. On November 19, 2007, Southern Company notified the FERC that the plan had been implemented and the FERC division of audits subsequently began an audit pertaining to compliance implementation and related matters, which is ongoing.
Generation Interconnection Agreements
In November 2004, generator company subsidiaries of Tenaska, Inc. (Tenaska), as counterparties to three previously executed interconnection agreements with subsidiaries of Southern Company, filed complaints at the FERC requesting that the FERC modify the agreements and that those Southern Company subsidiaries refund a total of $19 million previously paid for interconnection facilities. No other similar complaints are pending with the FERC.
On January 19, 2007, the FERC issued an order granting Tenaska’s requested relief. Although the FERC’s order required the modification of Tenaska’s interconnection agreements, under the provisions of the order, Southern Company determined that no refund was payable to Tenaska. Southern Company requested rehearing asserting that the FERC retroactively applied a new principle to existing interconnection agreements. Tenaska requested rehearing of FERC’s methodology for determining the amount of refunds. The requested rehearings were denied, and Southern Company and Tenaska have appealed the orders to the U.S. Circuit Court for the District of Columbia. The final outcome of this matter cannot now be determined.
PSC Matters
Alabama Power
In October 2005, the Alabama PSC approved a revision to the Rate Stabilization and Equalization Plan (Rate RSE) requested by Alabama Power. Effective January 2007, Rate RSE adjustments are based on forward-looking
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information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4% per year and any annual adjustment is limited to 5%. Rates remain unchanged when the retail return on common equity (ROE) is projected to be between 13% and 14.5%. If Alabama Power’s actual retail ROE is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail ROE fall below the allowed equity return range. The Rate RSE increase for 2008 is 3.24%, or $147 million annually, and was effective in January 2008. Under the terms of Rate RSE, the maximum increase for 2009 cannot exceed 4.76%. See Note 3 to the financial statements under “Alabama Power Retail Regulatory Matters” for further information.
Georgia Power
In December 2007, the Georgia PSC approved the retail rate plan for the years 2008 through 2010 (2007 Retail Rate Plan). Under the 2007 Retail Rate Plan, Georgia Power’s earnings will continue to be evaluated against a retail ROE range of 10.25% to 12.25%. Two-thirds of any earnings above 12.25% will be applied to rate refunds with the remaining one-third applied to an environmental compliance cost recovery (ECCR) tariff. Georgia Power has agreed that it will not file for a general base rate increase during this period unless its projected retail ROE falls below 10.25%. Retail base rates increased by approximately $99.7 million effective January 1, 2008 to provide for cost recovery of transmission, distribution, generation, and other investments, as well as increased operating costs. In addition, the ECCR tariff was implemented to allow for the recovery of costs for required environmental projects mandated by state and federal regulations. The ECCR tariff increased rates by approximately $222 million effective January 1, 2008. Georgia Power is required to file a general rate case by July 1, 2010, in response to which the Georgia PSC would be expected to determine whether the 2007 Retail Rate Plan should be continued, modified, or discontinued. See Note 3 to the financial statements under “Georgia Power Retail Regulatory Matters” for additional information.
Fuel Cost Recovery
The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Over the past several years, the traditional operating companies have continued to experience higher than expected fuel costs for coal, natural gas, and uranium. The traditional operating companies continuously monitor the under recovered fuel cost balance in light of these higher fuel costs. Each of the traditional operating companies received approval in 2006 and/or 2007 to increase its fuel cost recovery factor to recover existing under recovered amounts as well as projected future costs. At December 31, 2007, the amount of under recovered fuel costs included in the balance sheets was $1.1 billion compared to $1.3 billion at December 31, 2006.
Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changing the billing factor has no significant effect on the Company’s revenues or net income, but does impact annual cash flow. Based on their respective state PSC orders, a portion of the under recovered regulatory clause revenues for Alabama Power and Georgia Power was reclassified from current assets to deferred charges and other assets in the balance sheets. See Note 1 to the financial statements under “Revenues” and Note 3 to the financial statements under “Alabama Power Retail Regulatory Matters” and “Georgia Power Retail Regulatory Matters” for additional information.
Storm Damage Cost Recovery
Each traditional operating company maintains a reserve to cover the cost of damages from major storms to its transmission and distribution lines and generally the cost of uninsured damages to its generation facilities and other property. In addition, each of the traditional operating companies has been authorized by its state PSC to defer the portion of the major storm restoration costs that exceeded the balance in its storm damage reserve account. As of December 31, 2007, the under recovered balance in Southern Company’s storm damage reserve accounts totaled
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approximately $43 million, of which approximately $40 million and $3 million, respectively, are included in the balance sheets herein under “Other Current Assets” and “Other Regulatory Assets.”
See Notes 1 and 3 to the financial statements under “Storm Damage Reserves” and “Storm Damage Cost Recovery,” respectively, for additional information on these reserves. The final outcome of these matters cannot now be determined.
Mirant Matters
Mirant was an energy company with businesses that included independent power projects and energy trading and risk management companies in the U.S. and selected other countries. It was a wholly-owned subsidiary of Southern Company until its initial public offering in October 2000. In April 2001, Southern Company completed a spin-off to its shareholders of its remaining ownership, and Mirant became an independent corporate entity.
In July 2003, Mirant and certain of its affiliates filed for voluntary reorganization under Chapter 11 of the Bankruptcy Code. In January 2006, Mirant’s plan of reorganization became effective, and Mirant emerged from bankruptcy. As part of the plan, Mirant transferred substantially all of its assets and its restructured debt to a new corporation that adopted the name Mirant Corporation (Reorganized Mirant). Southern Company has certain contingent liabilities associated with guarantees of contractual commitments made by Mirant’s subsidiaries discussed in Note 7 to the financial statements under “Guarantees” and with various lawsuits discussed in Note 3 to the financial statements under “Mirant Matters.”
In December 2004, as a result of concluding an Internal Revenue Service (IRS) audit for the tax years 2000 and 2001, Southern Company paid approximately $39 million in additional tax and interest related to Mirant tax items and filed a claim in Mirant’s bankruptcy case for that amount. Through December 2007, Southern Company received from the IRS approximately $36 million in refunds related to Mirant. Southern Company believes it has a right to recoup the $39 million tax payment owed by Mirant from such tax refunds. As a result, Southern Company intends to retain the tax refunds and reduce its claim against Mirant for the payment of Mirant taxes by the amount of such refunds. MC Asset Recovery, a special purpose subsidiary of Reorganized Mirant, has objected to and sought to equitably subordinate the Southern Company tax claim in its fraudulent transfer litigation against Southern Company. Southern Company has reserved the approximately $3 million amount remaining with respect to its Mirant tax claim.
If Southern Company is ultimately required to make any additional payments either with respect to the IRS audit or its contingent obligations under guarantees of Mirant subsidiaries, Mirant’s indemnification obligation to Southern Company for these additional payments, if allowed, would constitute unsecured claims against Mirant, entitled to stock in Reorganized Mirant. See Note 3 to the financial statements under “Mirant Matters - Mirant Bankruptcy.”
In June 2005, Mirant, as a debtor in possession, and The Official Committee of Unsecured Creditors of Mirant Corporation filed a complaint against Southern Company in the U.S. Bankruptcy Court for the Northern District of Texas, which was amended in July 2005, February 2006, May 2006, and March 2007. In January 2006, MC Asset Recovery was substituted as plaintiff. The fourth amended complaint (the complaint) alleges that Southern Company caused Mirant to engage in certain fraudulent transfers and to pay illegal dividends to Southern Company prior to the spin-off. The complaint also seeks to recharacterize certain advances from Southern Company to Mirant for investments in energy facilities from debt to equity. The complaint further alleges that Southern Company is liable to Mirant’s creditors for the full amount of Mirant’s liability and that Southern Company breached its fiduciary duties to Mirant and its creditors, caused Mirant to breach fiduciary duties to its creditors, and aided and abetted breaches of fiduciary duties by Mirant’s directors and officers. The complaint also seeks recoveries under theories of restitution, unjust enrichment, and alter ego. In addition, the complaint alleges a claim under the Federal Debt Collection Procedure Act (FDCPA) to void certain transfers from Mirant to Southern Company. MC Asset
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Recovery claims to have standing to assert violations of the FDCPA and to recover property on behalf of the Mirant debtors’ estates. The complaint seeks monetary damages in excess of $2 billion plus interest, punitive damages, attorneys’ fees, and costs. Finally, the complaint includes an objection to Southern Company’s pending claims against Mirant in the Bankruptcy Court (which relate to reimbursement under the separation agreements of payments such as income taxes, interest, legal fees, and other guarantees described in Note 7 to the financial statements) and seeks equitable subordination of Southern Company’s claims to the claims of all other creditors. Southern Company served an answer to the complaint in April 2007.
In February 2006, the Company’s motion to transfer the case to the U.S. District Court for the Northern District of Georgia was granted. In May 2006, Southern Company filed a motion for summary judgment seeking entry of judgment against the plaintiff as to all counts in the complaint. In December 2006, the U.S. District Court for the Northern District of Georgia granted in part and denied in part the motion. As a result, certain breach of fiduciary duty claims alleged in earlier versions of the complaint were barred; all other claims may proceed. Southern Company believes there is no meritorious basis for the claims in the complaint and is vigorously defending itself in this action. See Note 3 to the financial statements under “Mirant Matters - MC Asset Recovery Litigation” for additional information. The ultimate outcome of these matters cannot be determined at this time.
Mirant Securities Litigation
In November 2002, Southern Company, certain former and current senior officers of Southern Company, and 12 underwriters of Mirant’s initial public offering were added as defendants in a class action lawsuit that several Mirant shareholders originally filed against Mirant and certain Mirant officers in May 2002. Several other similar lawsuits filed subsequently were consolidated into this litigation in the U.S. District Court for the Northern District of Georgia. The amended complaint is based on allegations related to alleged improper energy trading and marketing activities involving the California energy market, alleged false statements and omissions in Mirant’s prospectus for its initial public offering and in subsequent public statements by Mirant, and accounting-related issues previously disclosed by Mirant. The lawsuit purports to include persons who acquired Mirant securities between September 26, 2000 and September 5, 2002.
In July 2003, the court dismissed all claims based on Mirant’s alleged improper energy trading and marketing activities involving the California energy market. The other claims do not allege any improper trading and marketing activity, accounting errors, or material misstatements or omissions on the part of Southern Company but seek to impose liability on Southern Company based on allegations that Southern Company was a “control person” as to Mirant prior to the spin-off date. Southern Company filed an answer to the consolidated amended class action complaint in September 2003. Plaintiffs have also filed a motion for class certification.
During Mirant’s Chapter 11 proceeding, the securities litigation was stayed, with the exception of limited discovery. Since Mirant’s plan of reorganization has become effective, the stay has been lifted. In March 2006, the plaintiffs filed a motion for reconsideration requesting that the court vacate that portion of its July 2003 order dismissing the plaintiffs’ claims based upon Mirant’s alleged improper energy trading and marketing activities involving the California energy market. Southern Company and the other defendants have opposed the plaintiffs’ motion. On March 6, 2007, the court granted plaintiffs’ motion for reconsideration, reinstated the California energy market claims, and granted in part and denied in part defendants’ motion to compel certain class certification discovery. On March 21, 2007, defendants filed renewed motions to dismiss the California energy claims on grounds originally set forth in their 2003 motions to dismiss, but which were not addressed by the court. On July 27, 2007, certain defendants, including Southern Company, filed motions for reconsideration of the court’s denial of a motion seeking dismissal of certain federal securities laws claims based upon, among other things, certain alleged errors included in financial statements issued by Mirant. The ultimate outcome of this matter cannot be determined at this time.
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The plaintiffs have also stated that they intend to request that the court grant leave for them to amend the complaint to add allegations based upon claims asserted against Southern Company in the MC Asset Recovery litigation.
Under certain circumstances, Southern Company will be obligated under its Bylaws to indemnify the four current and/or former Southern Company officers who served as directors of Mirant at the time of its initial public offering through the date of the spin-off and who are also named as defendants in this lawsuit. The final outcome of this matter cannot now be determined.
Income Tax Matters
Leveraged Lease Transactions
Southern Company undergoes audits by the IRS for each of its tax years. The IRS has completed its audits of Southern Company’s consolidated federal income tax returns for all years prior to 2004. The IRS challenged Southern Company’s deductions related to three international lease transactions (SILO or sale-in-lease-out transactions), in connection with its audits of Southern Company’s 2000 through 2003 tax returns. In the third quarter 2006, Southern Company paid the full amount of the disputed tax and the applicable interest on the SILO issue for tax years 2000 and 2001 and filed a claim for refund which was denied by the IRS. The disputed tax amount was $79 million and the related interest approximately $24 million for these tax years. This payment, and the subsequent IRS disallowance of the refund claim, closed the issue with the IRS and Southern Company initiated litigation in the U.S. District Court for the Northern District of Georgia for a complete refund of tax and interest paid for the 2000 and 2001 tax years. The IRS also challenged the SILO deductions for the tax years 2002 and 2003. The estimated amount of disputed tax and interest for these tax years was approximately $83 million and $15 million, respectively. The tax and interest for these tax years was paid to the IRS in the fourth quarter 2006. Southern Company has accounted for both payments in 2006 as deposits. For tax years 2000 through 2007, Southern Company has claimed approximately $330 million in tax benefits related to these SILO transactions challenged by the IRS. These tax benefits relate to timing differences and do not impact total net income. Southern Company believes these transactions are valid leases for U.S. tax purposes and the related deductions are allowable. Southern Company is continuing to pursue resolution of these matters; however, the ultimate outcome cannot now be determined. In addition, the U.S. Senate is currently considering legislation that would disallow tax benefits after December 31, 2007 for SILO losses and other international leveraged lease transactions (such as lease-in-lease-out transactions). The ultimate impact on Southern Company’s net income and cash flow will be dependent on the outcome of the pending litigation and proposed legislation, but could be significant, and potentially material.
FSP 13-2 amended FASB Statement No. 13, “Accounting for Leases” to require recalculation of the rate of return and the allocation of income whenever the projected timing of the income tax cash flows generated by a leveraged lease is revised. Southern Company adopted FSP 13-2 effective January 1, 2007. The initial adoption required Southern Company to recognize a cumulative effect through retained earnings. Any future changes in the underlying lease assumptions that will change the projected or actual income tax cash flows will result in an additional recalculation of the net investment in the leases and will be recorded currently in income. See ACCOUNTING POLICIES - “New Accounting Standards - Leveraged Lease Transactions” herein and Note 3 to the financial statements under “Income Tax Matters” herein for further details.
Bonus Depreciation
On February 13, 2008, President Bush signed the Economic Stimulus Act of 2008 (Stimulus Act) into law. The Stimulus Act includes a provision that allows 50% bonus depreciation for certain property acquired in 2008 and placed in service in 2008 or, in certain limited cases, 2009. Southern Company is currently assessing the financial implications of the Stimulus Act; however, the ultimate impact cannot be determined at this time.
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Georgia State Income Tax Credits
Georgia Power’s 2005 through 2007 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. Georgia Power has also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue has not responded to these claims. On July 24, 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. If allowed, these claims could have a significant, possibly material, positive effect on Southern Company’s net income. If Georgia Power is not successful, payment of the related state tax could have a significant, possibly material, negative effect on Southern Company’s cash flow. The ultimate outcome of this matter cannot now be determined.
Internal Revenue Code Section 199 Domestic Production Deduction
The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in the Internal Revenue Code Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for years 2007 through 2009, and a 9% rate applicable for all years after 2009. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.
Construction Projects
Integrated Coal Gasification Combined Cycle
In December 2005, Southern Power and the Orlando Utilities Commission (OUC) executed definitive agreements for development of a 285-megawatt IGCC project in Orlando, Florida. The definitive agreements provided that Southern Power would own at least 65% of the gasifier portion of the IGCC project. OUC would own the remainder of the gasifier portion and 100% of the combined cycle portion of the IGCC project. Southern Power signed cooperative agreements with the DOE that provided up to $293.8 million in grant funding for the gasification portion of this project. The IGCC project was expected to begin commercial operation in 2010. Due to continuing uncertainty surrounding potential state regulations relating to greenhouse gas emissions, Southern Power and OUC mutually agreed to terminate the construction of the gasifier portion of the IGCC project in November 2007. Southern Power will continue construction of the gas-fired combined cycle generating facility under a fixed price, long-term contract for engineering, procurement, and construction services. The Company recorded an after-tax loss of approximately $10.7 million in the fourth quarter of 2007 related to the cancellation of the gasifier portion of the IGCC project.
In June 2006, Mississippi Power filed an application with the United States Department of Energy (DOE) for certain tax credits available to projects using clean coal technologies under the Energy Policy Act of 2005. The proposed project is an advanced coal gasification facility located in Kemper County, Mississippi that would use locally mined lignite coal. The proposed 693-megawatt plant is expected to require an approximate investment of $1.5 billion, excluding the mine costs, and is expected to be completed in 2013. The DOE subsequently certified the project and in November 2006 the IRS allocated Internal Revenue Code tax credits to Mississippi Power of $133 million. The utilization of these credits is dependent upon meeting the certification requirements for the project under the Internal Revenue Code. The plant would use an air-blown IGCC technology that generates power from low-rank coals and coals with high moisture or high ash content. These coals, which include lignite, make up half the proven U.S. and worldwide coal reserves. Mississippi Power is undertaking a feasibility assessment of the project which could take up to two years. Approval by various regulatory agencies, including the Mississippi PSC, will also be required if the project proceeds. The Mississippi PSC has authorized Mississippi Power to create a regulatory asset for the approved retail portion of the costs associated with the generation resource planning, evaluation, and screening
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activities up to approximately $23.8 million ($16 million for the retail portion). The retail portion of these costs will be charged to and remain as a regulatory asset until the Mississippi PSC determines the prudence and ultimate recovery, which decision is expected in January 2009.
The final outcome of these matters cannot now be determined.
Nuclear
In August 2006, as part of a potential expansion of Plant Vogtle, Georgia Power and Southern Nuclear Operating Company, Inc. (SNC) filed an application with the Nuclear Regulatory Commission (NRC) for an early site permit (ESP) on behalf of the owners of Plant Vogtle. In addition, Georgia Power and SNC notified the NRC of their intent to apply for a combined construction and operating license (COL) in 2008. Ownership agreements have been signed with each of the existing Plant Vogtle co-owners. See Note 4 to the financial statements for additional information on these co-owners. In June 2006, the Georgia PSC approved an accounting order that would allow Georgia Power to defer for future recovery the ESP and COL costs, of which Georgia Power’s portion is estimated to total approximately $51 million. At December 31, 2007, approximately $28.4 million is included in deferred charges and other assets. No final decision has been made regarding actual construction. Any new generation resource must be certified by the Georgia PSC in a separate proceeding.
Southern Company also is participating in NuStart Energy Development, LLC (NuStart Energy), a broad-based nuclear industry consortium formed to share the cost of developing a COL and the related NRC review. NuStart Energy was organized to complete detailed engineering design work and to prepare COL applications for two advanced reactor designs. COLs for the two reactor designs were submitted to the NRC during the fourth quarter of 2007. The COLs ultimately are expected to be transferred to one or more of the consortium companies; however, at this time, none of them have committed to build a new nuclear plant.
Southern Company is also exploring other possibilities relating to nuclear power projects, both on its own or in partnership with other utilities. The final outcome of these matters cannot now be determined.
Nuclear Relicensing
In January 2002, the NRC granted Georgia Power a 20-year extension of the licenses for both units at Plant Hatch which permits the operation of Units 1 and 2 until 2034 and 2038, respectively. Georgia Power filed an application with the NRC in June 2007 to extend the licenses for Plant Vogtle Units 1 and 2 for an additional 20 years. Georgia Power anticipates the NRC may make a decision regarding the license extension for Plant Vogtle as early as 2009.
Other Matters
Southern Company is involved in various other matters being litigated, regulatory matters, and certain tax-related issues that could affect future earnings. In addition, Southern Company is subject to certain claims and legal actions arising in the ordinary course of business. Southern Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current
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proceedings would have a material adverse effect on Southern Company’s financial statements. See Note 3 to the financial statements for information regarding material issues.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on Southern 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 discussed the development and selection of the critical accounting policies and estimates described below with the Audit Committee of Southern Company’s Board of Directors.
Electric Utility Regulation
Southern Company’s traditional operating companies, which comprise approximately 91% of Southern Company’s total earnings for 2007, are subject to retail regulation by their respective state PSCs and wholesale regulation by the FERC. These regulatory agencies set the rates the traditional operating companies are permitted to charge customers based on allowable costs. As a result, the traditional operating companies apply FASB Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), which requires the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of SFAS No. 71 has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the traditional operating companies; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on the Company’s results of operations than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines and accounting principles generally accepted in the United States. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s financial statements.
Contingent Obligations
Southern Company and its subsidiaries are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject them to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. Southern Company periodically evaluates its exposure to such risks and records reserves for those matters where a loss is considered probable and reasonably estimable in accordance with generally accepted accounting principles. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect Southern Company’s financial statements. These events or conditions include the following:
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•
Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances, hazardous and solid wastes, and other environmental matters.
•
Changes in existing income tax regulations or changes in IRS or state revenue department interpretations of existing regulations.
•
Identification of additional sites that require environmental remediation or the filing of other complaints in which Southern Company or its subsidiaries may be asserted to be a potentially responsible party.
•
Identification and evaluation of other potential lawsuits or complaints in which Southern Company or its subsidiaries may be named as a defendant.
•
Resolution or progression of existing matters through the legislative process, the court systems, the IRS, the FERC, or the EPA.
Unbilled Revenues
Revenues related to the sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, and power delivery volume and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company’s results of operations.
Leveraged Leases
FASB Staff Position No. FAS 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction” (FSP 13-2) amended FASB Statement No. 13, “Accounting for Leases” to require recalculation of the rate of return and the allocation of income whenever the projected timing of the income tax cash flows generated by a leveraged lease is revised. Southern Company adopted FSP 13-2 effective January 1, 2007. The initial adoption required Southern Company to record a cumulative effect to retained earnings. Any future changes in the underlying lease assumptions, such as the expected resolution date of the ongoing SILO litigation, which will change the projected or actual income tax cash flows will result in an additional recalculation of the net investment in the leases and will be recorded currently in income. See FUTURE EARNINGS POTENTIAL - “Income Tax Matters - Leveraged Lease Transactions” above and Note 3 to the financial statements under “Income Tax Matters” herein for further details.
New Accounting Standards
Income Taxes
On January 1, 2007, Southern Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), which requires companies to determine whether it is “more likely than not” that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. It also provides guidance on the recognition, measurement, and classification of income tax uncertainties, along with any related interest and penalties. The provisions of FIN 48 were applied to all tax positions beginning January 1, 2007. The impact on Southern Company’s financial
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statements was a reduction to beginning 2007 retained earnings of approximately $15 million related to Southern Company’s SILO transactions. See Note 5 to the financial statements for additional information.
Leveraged Leases
Effective January 1, 2007, Southern Company adopted FSP 13-2. The cumulative effect of initially adopting FSP 13-2 was recorded as a reduction to beginning retained earnings. For the LILO (lease-in-lease-out) transaction settled with the IRS in February 2005, the cumulative effect of adopting FSP 13-2 was a $17 million reduction in retained earnings. With respect to Southern Company’s SILO transactions, the adoption of FSP 13-2 reduced retained earnings by $108 million. The adjustments to retained earnings are non-cash charges and will be recognized as income over the remaining terms of the affected leases. The adoption of FSP 13-2 also resulted in a reduction to net income of approximately $15 million during 2007. Any future changes in the projected or actual income tax cash flows will result in an additional recalculation of the net investment in the leases and will be recorded currently in income.
Pensions and Other Postretirement Plans
On December 31, 2006, Southern Company adopted FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS No. 158), which requires recognition of the funded status of its defined benefit postretirement plans in the balance sheets. Additionally, SFAS No. 158 will require Southern Company to change the measurement date for its defined benefit postretirement plan assets and obligations from September 30 to December 31 beginning with the year ending December 31, 2008. See Note 2 to the financial statements for additional information.
Fair Value Measurement
The FASB issued FASB Statement No. 157, “Fair Value Measurements” (SFAS No. 157) in September 2006. SFAS No. 157 provides guidance on how to measure fair value where it is permitted or required under other accounting pronouncements. SFAS No. 157 also requires additional disclosures about fair value measurements. Southern Company adopted SFAS No. 157 in its entirety on January 1, 2008, with no material effect on its financial condition or results of operations.
Fair Value Option
In February 2007, the FASB issued FASB Statement No. 159, “Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115” (SFAS No. 159). This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. Southern Company adopted SFAS No. 159 on January 1, 2008, with no material effect on its financial condition or results of operations.
Business Combinations
In December 2007, the FASB issued FASB Statement No. 141 (revised 2007), “Business Combinations (SFAS No. 141R). SFAS No. 141R, when adopted, will significantly change the accounting for business combinations, specifically the accounting for contingent consideration, contingencies, acquisition costs, and restructuring costs. Southern Company plans to adopt SFAS No. 141R on January 1, 2009. It is likely that the adoption of SFAS No. 141R will have a significant impact on the accounting for any business combinations completed by Southern Company after January 1, 2009.
In December 2007, the FASB issued FASB Statement No. 160, “Non-controlling Interests in Consolidated Financial Statements” (SFAS No. 160). SFAS No. 160 amends Accounting Research Bulletin No. 51, “Consolidated
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Financial Statements” to establish accounting and reporting standards for the non-controlling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary should be reported as equity in the consolidated financial statements and establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation. Southern Company plans to adopt SFAS No. 160 on January 1, 2009. Southern Company is currently assessing its impact, if any.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Company’s financial condition remained stable at December 31, 2007. Net cash provided from operating activities totaled $3.4 billion, an increase of $575 million as compared to 2006. The increase was primarily due to an increase in net income as previously discussed, an increase in cash collections from previously deferred fuel and storm damage costs, and a reduction in cash outflows compared to the previous year in fossil fuel inventory. In 2006, net cash provided from operating activities increased over the previous year by $290 million primarily as a result of a decrease in under recovered storm restoration costs, a decrease in accounts payable from year-end 2005 amounts that included substantial hurricane-related expenditures, partially offset by an increase in fossil fuel inventory. In 2005, net cash provided from operating activities totaled $2.5 billion, a decrease of $165 million as compared to 2004 primarily due to higher fuel costs at the traditional operating companies, partially offset by increases in base rates and fuel recovery rates.
Net cash used for investing activities in 2007 totaled $3.7 billion primarily due to property additions to utility plant of $3.5 billion. In 2006, net cash used for investing activities was $2.8 billion primarily due to property additions to utility plant of $3.0 billion, partially offset by proceeds from the sale of Southern Company Gas LLC and the receipt by Mississippi Power of capital grant proceeds related to Hurricane Katrina. In 2005, net cash used for investing activities was $2.6 billion primarily due to property additions to utility plant of $2.4 billion.
Net cash provided from financing activities totaled $348 million in 2007 primarily due to replacement of short-term debt with longer term financing and cash raised from common stock programs. In 2006 and 2005, net cash used for financing activities was $21 million and $67 million, respectively.
Significant balance sheet changes in 2007 include an increase in long-term debt of $1.6 billion primarily to replace short-term debt and to provide funds for the Company’s continuous construction program. Balance sheet changes also include an increase in property, plant, and equipment of $2.2 billion and an increase in prepaid pension assets of $820 million with a corresponding increase in other regulatory liabilities.
At the end of 2007, the closing price of Southern Company’s common stock was $38.75 per share, compared with book value of $16.23 per share. The market-to-book value ratio was 239% at the end of 2007, compared with 242% at year-end 2006.
Southern Company, each of the traditional operating companies, and Southern Power have received investment grade ratings from the major rating agencies with respect to debt, preferred securities, preferred stock, and/or preference stock. SCS has an investment grade corporate credit rating.
Sources of Capital
Southern Company intends to meet its future capital needs through internal cash flow and external security issuances. Equity capital can be provided from any combination of the Company’s stock plans, private placements, or public offerings. The amount and timing of additional equity capital to be raised in 2008, as well as in subsequent years, will be contingent on Southern Company’s investment opportunities.
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The traditional operating companies and Southern Power plan to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, security issuances, term loans, and short-term borrowings. However, the type and timing of any financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. The issuance of securities by the traditional operating companies is generally subject to the approval of the applicable state PSC. In addition, the issuance of all securities by Mississippi Power and Southern Power and short-term securities by Georgia Power is generally subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, Southern Company and certain of its subsidiaries file registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the amounts, if any, registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.
Southern Company, each traditional operating company, and Southern Power obtain 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 each company are not commingled with funds of any other company.
Southern Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs as well as scheduled maturities of long-term debt. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to the capital markets, including commercial paper programs, to meet liquidity needs.
At December 31, 2007, Southern Company and its subsidiaries had approximately $201 million of cash and cash equivalents and $4.1 billion of unused credit arrangements with banks, of which $811 million expire in 2008 and $3.3 billion expire in 2012. Approximately $79 million of the credit facilities expiring in 2008 allow for the execution of term loans for an additional two-year period, and $500 million allow for the execution of one-year term loans. Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of the individual company. Southern Company and its subsidiaries are currently in compliance with all such covenants. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.
Financing Activities
During 2007, Southern Company and its subsidiaries issued $3.4 billion of senior notes, $456 million of obligations related to tax-exempt bonds, and $470 million of preference stock. Interest rate hedges of $1.4 billion notional amount were settled at a gain of $9 million related to the issuances. The security issuances were used to redeem $2.6 billion of long-term debt, to reduce short-term indebtedness, to fund Southern Company’s ongoing construction program, and for general corporate purposes.
Subsequent to December 31, 2007, Alabama Power issued $300 million of senior notes. The proceeds from the sale of the senior notes were used to repay a portion of outstanding short-term indebtedness and for other general corporate purposes, including Alabama Power’s continuous construction program.
Off-Balance Sheet Financing Arrangements
In 2001, Mississippi Power began the initial 10-year term of a lease agreement for a combined cycle generating facility built at Plant Daniel for approximately $370 million. In 2003, the generating facility was acquired by Juniper Capital L.P. (Juniper), a limited partnership whose investors are unaffiliated with Mississippi Power. Simultaneously, Juniper entered into a restructured lease agreement with Mississippi Power. Juniper has also entered into leases with other parties unrelated to Mississippi Power. The assets leased by Mississippi Power comprise less than 50% of Juniper’s assets. Mississippi Power is not required to consolidate the leased assets and
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2007 Annual Report
related liabilities, and the lease with Juniper is considered an operating lease. The lease also provides for a residual value guarantee, approximately 73% of the acquisition cost, by Mississippi Power that is due upon termination of the lease in the event that Mississippi Power does not renew the lease or purchase the assets and that the fair market value is less than the unamortized cost of the assets. See Note 7 to the financial statements under “Operating Leases” for additional information.
Credit Rating Risk
Southern Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and Baa2, or BBB- or Baa3 or below. These contracts are primarily for physical electricity purchases and sales. At December 31, 2007, the maximum potential collateral requirements at a BBB and Baa2 rating were approximately $9 million and at a BBB- or Baa3 rating were approximately $297 million. At December 31, 2007, the maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $1.0 billion. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash.
Southern Company’s operating subsidiaries are also party to certain agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade for Alabama Power and/or Georgia Power. These agreements are primarily for natural gas and power price risk management activities. At December 31, 2007, Southern Company’s total exposure to these types of agreements was approximately $15 million.
Market Price Risk
Southern 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 the exposures to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. Company policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
To mitigate future exposure to a change in interest rates, the Company enters into forward starting interest rate swaps and other derivatives that have been designated as hedges. Derivatives outstanding at December 31, 2007 have a notional amount of $505 million and are related to anticipated debt issuances over the next two years. The weighted average interest rate on $3.4 billion of long-term variable interest rate exposure that has not been hedged at January 1, 2008 was 4.5%. On January 8, 2008, Georgia Power converted $115 million of floating rate pollution control bonds to a fixed interest rate, reducing the Company’s exposure to $3.3 billion. Beginning in February 2008, Georgia Power and Alabama Power hedged a total of $601 million and $576 million, respectively, of floating rate exposure, further reducing the Company’s long-term variable interest rate exposure to $2.1 billion. If Southern Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $33.7 million at January 1, 2008. Subsequent to the recently completed transactions, a 100 basis point change in interest rates for all unhedged variable rate long-term debt would affect annualized interest expense by approximately $22.2 million. For further information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”
Of the Company’s remaining $2.1 billion of variable interest rate exposure, approximately $1.1 billion relates to tax-exempt auction rate pollution control bonds. Recent weakness in the auction markets has resulted in failed auctions during February 2008 of some of the $1.1 billion auction rate securities which results in significantly higher interest
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2007 Annual Report
rates during the failed auctions period. The Company has sent notice of conversion of $946 million of these auction rate securities to alternative interest rate determination methods and plans to remarket all remaining auction rate securities in a timely manner. None of the securities are insured or backed by letters of credit that would require approval of a guarantor or security provider. It is not expected that the higher rates as a result of the weakness in the auction markets will be material.
Due to cost-based rate regulations, the traditional operating companies have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. In addition, Southern Power’s exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts generally shift substantially all fuel cost responsibility to the purchaser. To mitigate residual risks relative to movements in electricity prices, the traditional operating companies enter into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts for natural gas purchases. The traditional operating companies have implemented fuel-hedging programs at the instruction of their respective state PSCs.
The changes in fair value of energy-related derivative contracts and year-end valuations were as follows at December 31:
(a)
Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
Unrealized gains and losses from mark-to-market adjustments on derivative contracts related to the traditional operating companies’ fuel hedging programs are recorded as regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are recovered through the traditional operating companies’ fuel cost recovery clauses. In addition, unrealized gains and losses on energy-related derivatives used by Southern Power to hedge anticipated purchases and sales are deferred in other comprehensive income. Gains and losses on derivative contracts that are not designated as hedges are recognized in the statements of income as incurred. At December 31, 2007, the fair value gains/(losses) of energy-related derivative contracts were reflected in the financial statements as follows:
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2007 Annual Report
Unrealized pre-tax gains and losses from energy-related derivative contracts recognized in income were not material for any year presented.
Southern Company is exposed to market price risk in the event of nonperformance by counterparties to the energy-related derivative contracts. Southern Company’s policy is to enter into agreements with counterparties that have investment grade credit ratings by Moody’s and Standard & Poor’s or with counterparties who have posted collateral to cover potential credit exposure. Therefore, Southern Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”
To reduce Southern Company’s exposure to changes in the value of synthetic fuel tax credits, which were impacted by changes in oil prices, the Company entered into derivative transactions indexed to oil prices. Because these transactions are not designated as hedges, the gains and losses are recognized in the statements of income as incurred. For 2007, the fair value gain recognized in income for mark to market transactions was $27 million. For 2006 and 2005, the fair value losses recognized in income for mark to market transactions were $32 million and $7 million, respectively. For further information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”
Capital Requirements and Contractual Obligations
The construction program of Southern Company is currently estimated to be $4.5 billion for 2008, $4.8 billion for 2009, and $4.3 billion for 2010. Environmental expenditures included in these estimated amounts are $1.8 billion, $1.5 billion, and $0.6 billion for 2008, 2009, and 2010, respectively. Actual construction costs may vary from these estimates because of changes in such factors as: business conditions; environmental statutes and regulations; nuclear plant regulations; FERC rules and regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
As a result of NRC requirements, Alabama Power and Georgia Power have external trust funds for nuclear decommissioning costs; however, Alabama Power 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, Southern Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the traditional operating companies’ respective regulatory commissions.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt and preferred securities, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, and other purchase commitments are as follows. See Notes 1, 6, and 7 to the financial statements for additional information.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2007 Annual Report
Contractual Obligations
(a)
All amounts are reflected based on final maturity dates. Southern Company and its subsidiaries plan to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2008, 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)
On October 26, 2007, Alabama Power announced the redemption on January 1, 2008 of 1,250 shares of Flexible Money Market Class A Preferred Stock (Series 2003A), Cumulative, Par Value $1 Per Share (Stated Capital $100,000 Per Share).
(c)
Preferred and preference stock do not mature; therefore, amounts are provided for the next five years only.
(d)
For additional information, see Notes 1 and 6 to the financial statements.
(e)
The timing related to the $108 million in unrecognized tax benefits and interest payments in individual years beyond 12 months cannot be reasonably and reliably estimated due to uncertainties in the timing of the effective settlement of tax positions. Of this $108 million, $71 million is expected to represent cash payments. See Notes 3 and 5 to the financial statements for additional information.
(f)
Southern Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for 2007, 2006, and 2005 were $3.7 billion, $3.5 billion, and $3.5 billion, respectively.
(g)
Southern Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures excluding those amounts related to contractual purchase commitments for nuclear fuel. At December 31, 2007, significant purchase commitments were outstanding in connection with the construction program.
(h)
As part of Southern Company’s program to reduce sulfur dioxide emissions from certain of its coal plants, the traditional operating companies are constructing certain equipment and have entered into various long-term commitments for the procurement of limestone to be used in such equipment.
(i)
Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2007.
(j)
Long-term service agreements include price escalation based on inflation indices.
(k)
Southern Company forecasts postretirement trust contributions over a three-year period. No contributions related to Southern Company’s pension trust are currently expected during this period. See Note 2 to the financial statements for additional information related to the pension and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from Southern Company’s corporate assets.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2007 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
Southern Company’s 2007 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for the wholesale business, customer growth, storm damage cost recovery and repairs, fuel cost recovery, environmental regulations and expenditures, earnings growth, dividend payout ratios, access to sources of capital, projections for postretirement benefit trust contributions, financing activities, completion of construction projects, impacts of adoption of new accounting rules, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
•
the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, or particulate matter and other substances, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
•
current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, IRS audits, and Mirant matters;
•
the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company’s subsidiaries operate;
•
variations in demand for electricity, including those relating to weather, the general economy, population, and business growth (and declines), and the effects of energy conservation measures;
•
available sources and costs of fuel;
•
effects of inflation;
•
ability to control costs;
•
investment performance of Southern Company’s employee benefit plans;
•
advances in technology;
•
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and storm restoration cost recovery;
•
the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;
•
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 Southern Company or its subsidiaries;
•
the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due;
•
the ability to obtain new short- and long-term contracts with neighboring utilities;
•
the direct or indirect effect on Southern Company’s business resulting from terrorist incidents and the threat of terrorist incidents;
•
interest rate fluctuations and financial market conditions and the results of financing efforts, including Southern Company’s and its subsidiaries’ credit ratings;
•
the ability of Southern Company and its subsidiaries to obtain additional generating capacity at competitive prices;
•
catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as an avian influenza, or other similar occurrences;
•
the direct or indirect effects on Southern Company’s business resulting from incidents similar to the August 2003 power outage in the Northeast;
•
the effect of accounting pronouncements issued periodically by standard setting bodies; and
•
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.
Southern Company expressly disclaims any obligation to update any forward-looking statements.
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CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2007, 2006, and 2005
Southern Company and Subsidiary Companies 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2007, 2006, and 2005
Southern Company and Subsidiary Companies 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2007 and 2006
Southern Company and Subsidiary Companies 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
II-48
CONSOLIDATED BALANCE SHEETS
At December 31, 2007 and 2006
Southern Company and Subsidiary Companies 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
II-49
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 2007 and 2006
Southern Company and Subsidiary Companies 2007 Annual Report
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CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2007 and 2006
Southern Company and Subsidiary Companies 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
For the Years Ended December 31, 2007, 2006, and 2005
Southern Company and Subsidiary Companies 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2007, 2006, and 2005
Southern Company and Subsidiary Companies 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 2007 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
The Southern Company (the Company) is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power, are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, and manages generation assets and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and the subsidiary companies. SouthernLINC Wireless provides digital wireless communications services to the traditional operating companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy-related businesses. The investments in synthetic fuels ended on December 31, 2007. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants.
The financial statements reflect Southern Company’s investments in the subsidiaries on a consolidated basis. The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities where the Company is not the primary beneficiary. All material intercompany transactions have been eliminated in consolidation.
The traditional operating companies, Southern Power, and certain of their subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC) and the traditional operating companies are also subject to regulation by their respective state public service commissions (PSC). The companies follow accounting principles generally accepted in the United States and comply with the accounting policies and practices prescribed by their respective commissions. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from those estimates.
Reclassifications
Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no effect on total assets, net income, cash flows, or earnings per share.
The balance sheets and the statements of cash flows have been modified to combine “Long-term Debt Payable to Affiliate Trusts” into “Long-term Debt.” Correspondingly, the statements of income were modified to report “Interest expense to affiliate trusts” together with “Interest expense, net of amounts capitalized.” Due to the immateriality of earnings from discontinued operations during all periods presented, the statements of income and the statements of comprehensive income have been modified to report net income without a separate disclosure of the effect from discontinued operations. Also, due to immateriality, the statements of cash flows were adjusted to reflect “Tax benefit of stock options” together with the amounts reported in “Other, net.”
Related Party Transactions
Alabama Power and Georgia Power purchased synthetic fuel from Alabama Fuel Products, LLC (AFP), an entity in which Southern Holdings held a 30% ownership interest until July 2006, when its ownership interest was terminated. Total fuel purchases through June 2006 and for the year 2005 were $354 million and $507 million, respectively. Synfuel Services, Inc. (SSI), another subsidiary of Southern Holdings, provided fuel transportation services to AFP that were ultimately reflected in the cost of the synthetic fuel billed to Alabama Power and Georgia Power. In connection with these services, the related revenues of approximately $62 million and $83 million through June 2006 and for the year 2005, respectively, have been eliminated against fuel expense in the financial
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NOTES (continued)
Southern Company and Subsidiary Companies 2007 Annual Report
statements. SSI also provided additional services to AFP, as well as to a related party of AFP. Revenues from these transactions totaled approximately $24 million and $40 million through June 2006 and for the year 2005, respectively.
Subsequent to the termination of Southern Company’s membership interest in AFP, Alabama Power and Georgia Power continued to purchase an additional $750 million and $384 million in fuel from AFP in 2007 and 2006, respectively. SSI continued to provide fuel transportation services of $131 million in 2007 and $62 million in 2006, which were eliminated against fuel expense in the financial statements. SSI also provided other additional services to AFP and a related party of AFP totaling $47 million and $21 million in 2007 and 2006, respectively. The synthetic fuel investments and related party transactions were terminated on December 31, 2007.
Regulatory Assets and Liabilities
The traditional operating companies are subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
(a)
Asset retirement and removal liabilities are recorded, deferred income tax assets are recovered, and deferred tax liabilities are amortized over the related property lives, which may range up to 65 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.
(b)
Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 50 years.
(c)
Recorded as earned by employees and recovered as paid, generally within one year.
(d)
Recorded and recovered or amortized as approved by the appropriate state PSCs.
(e)
Amortized over a four-year period that ended in 2007.
(f)
Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 under “Retirement Benefits.”
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NOTES (continued)
Southern Company and Subsidiary Companies 2007 Annual Report
In the event that a portion of a traditional operating company’s operations is no longer subject to the provisions of SFAS No. 71, such company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional operating company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under “Alabama Power Retail Regulatory Matters,” “Georgia Power Retail Regulatory Matters,” and “Storm Damage Cost Recovery” for additional information.
Revenues
Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract periods. 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 traditional operating companies 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.
Retail fuel cost recovery mechanisms vary by each retail operating company, but in general, the process requires periodic filings with the appropriate state PSC. Alabama Power continuously monitors the under/over recovered balance and files for a revised fuel rate when management deems appropriate. Georgia Power is required to file a new fuel case no later than March 1, 2008. Gulf Power is required to notify the Florida PSC if the projected fuel revenue over or under recovery exceeds 10% of the projected fuel revenue applicable for the period and indicate if an adjustment to the fuel cost recovery factor is being requested. Mississippi Power is required to file for an adjustment to the fuel cost recovery factor annually. See Note 3 under “Alabama Power Retail Regulatory Matters” and “Georgia Power Retail Regulatory Matters” for additional information.
Southern 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 the cost of purchased emission allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel.
Nuclear Fuel Disposal Costs
Alabama Power and Georgia Power have contracts with the United States, acting through the U.S. Department of Energy (DOE), that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contracts, and Alabama Power and Georgia Power are pursuing legal remedies against the government for breach of contract.
On July 9, 2007, the U.S. Court of Federal Claims awarded Georgia Power a total of $30 million, based on its ownership interests, and awarded Alabama Power $17.3 million, representing all of the direct costs of the expansion of spent nuclear fuel storage facilities from 1998 through 2004. On July 24, 2007, the government filed a motion for reconsideration, which was denied on November 1, 2007. The government filed an appeal on January 2, 2008. No amounts have been recognized in the financial statements as of December 31, 2007. The final outcome of this matter cannot be determined at this time, but no material impact on net income is expected as any award received is expected to be returned to customers.
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NOTES (continued)
Southern Company and Subsidiary Companies 2007 Annual Report
Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into 2014. Construction of an on-site dry storage facility at Plant Vogtle is expected to begin in sufficient time to maintain pool full-core discharge capability. At Plants Hatch and Farley, on-site dry storage facilities are operational and can be expanded to accommodate spent fuel through the expected life of each plant.
Income and Other Taxes
Southern Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.
In accordance with FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), Southern 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 on the effect of adopting FIN 48.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction.
Southern Company’s property, plant, and equipment consisted of the following at December 31:
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific state PSC orders. Alabama Power accrues estimated nuclear refueling costs in advance of the unit’s next refueling outage. Georgia Power defers and amortizes nuclear refueling costs over the unit’s operating cycle before the next refueling. The refueling cycles for Alabama Power and Georgia Power range from 18 to 24 months for each unit. In accordance with a Georgia PSC order, Georgia Power also defers the costs of certain significant inspection costs for the combustion turbines at Plant McIntosh and amortizes such costs over 10 years, which approximates the expected maintenance cycle.
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NOTES (continued)
Southern Company and Subsidiary Companies 2007 Annual Report
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.0% in 2007, 3.0% in 2006, and 2.9% in 2005. Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC for the traditional operating companies. Accumulated depreciation for utility plant in service totaled $17.0 billion and $16.2 billion at December 31, 2007 and 2006, respectively. 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 is removed from the balance sheet accounts and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.
Under Georgia Power’s retail rate plan for the three years ended December 31, 2007 (2004 Retail Rate Plan), Georgia Power was ordered to recognize Georgia PSC-certified capacity costs in rates evenly over the three years covered by the 2004 Retail Rate Plan. Georgia Power recorded credits to amortization of $19 million and $14 million in 2007 and 2006, respectively, and an increase to amortization of $33 million in 2005. See Note 3 under “Retail Regulatory Matters - Rate Plans” for additional information.
In May 2004, the Mississippi PSC approved Mississippi Power’s request to reclassify 266 megawatts of Plant Daniel units 3 and 4 capacity to jurisdictional cost of service effective January 1, 2004 and authorized Mississippi Power to include the related costs and revenue credits in jurisdictional rate base, cost of service, and revenue requirement calculations for purposes of retail rate recovery. Mississippi Power amortized the related regulatory liability pursuant to the Mississippi PSC’s order as follows: $17 million in 2004, $25 million in 2005, $13 million in 2006, and $6 million in 2007, resulting in increases to earnings in each of those years.
Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from 3 to 25 years. Accumulated depreciation for other plant in service totaled $429 million and $405 million at December 31, 2007 and 2006, respectively.
Asset Retirement Obligations and Other Costs of Removal
Asset retirement obligations are computed as the present value of the ultimate costs for an asset’s future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. The Company has received accounting guidance from the various state PSCs allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations will continue to be reflected in the balance sheets as a regulatory liability.
The liability recognized to retire long-lived assets primarily relates to the Company’s nuclear facilities, Plants Farley, Hatch, and Vogtle. The fair value of assets legally restricted for settling retirement obligations related to nuclear facilities as of December 31, 2007 was $1.1 billion. In addition, the Company has retirement obligations related to various landfill sites and underground storage tanks. In connection with the adoption of FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), Southern Company also recorded additional asset retirement obligations (and assets) of approximately $153 million, primarily related to asbestos removal and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, co-generation facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized under FASB Statement No. 143 “Accounting for Asset Retirement
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Obligations” (SFAS No. 143) and FIN 47 and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the various state PSCs, and are reflected in the balance sheets. See “Nuclear Decommissioning” herein for further information on amounts included in rates.
Details of the asset retirement obligations included in the balance sheets are as follows:
Nuclear Decommissioning
The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds to comply with the NRC’s regulations. Use of the funds is restricted to nuclear decommissioning activities and the funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and state PSCs, as well as the Internal Revenue Service (IRS). The trust funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are classified as available-for-sale.
The trust funds are included in the balance sheets at fair value, as obtained from quoted market prices for the same or similar investments. As the external trust funds are actively managed by unrelated parties with limited direction from the Company, the Company does not have the ability to choose to hold securities with unrealized losses until recovery. Through 2005, the Company considered other-than-temporary impairments to be immaterial. However, since the January 1, 2006 effective date of FASB Staff Position FAS 115-1/124-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (FSP No. 115-1), the Company considers all unrealized losses to represent other-than-temporary impairments. The adoption of FSP No. 115-1 had no impact on the results of operations, cash flows, or financial condition of the Company as all losses have been and continue to be recorded through a regulatory liability, whether realized, unrealized, or identified as other-than-temporary.
Details of the securities held in these trusts at December 31, 2007 were as follows:
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The contractual maturities of debt securities at December 31, 2007 are as follows: $35.7 million in 2008; $67.3 million in 2009-2012; $58.1 million in 2013-2017; and $151.2 million thereafter.
Sales of the securities held in the trust funds resulted in cash proceeds of $774.8 million, $743.1 million, and $596.3 million in 2007, 2006, and 2005, respectively, all of which were re-invested. Realized gains and other-than-temporary impairment losses were $78.3 million and $76.3 million, respectively, in 2007 and $39.8 million and $30.3 million, respectively, in 2006. Net realized gains were $22.5 million in 2005. Realized gains and other-than-temporary impairment losses are determined on a specific identification basis. In accordance with regulatory guidance, all realized and unrealized gains and losses are included in the regulatory liability for asset retirement obligations in the balance sheets and are not included in net income or other comprehensive income. Unrealized gains and other-than-temporary impairment losses are considered non-cash transactions for purposes of the statements of cash flow.
Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the respective state PSCs. 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. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC. At December 31, 2007, the accumulated provisions for decommissioning were as follows:
Site study cost is the estimate to decommission a specific facility as of the site study year. The estimated costs of decommissioning based on the most current studies, which were performed in 2003 for Plant Farley and in 2006 for the Georgia Power plants, were as follows for Alabama Power’s Plant Farley and Georgia Power’s ownership interests in Plants Hatch and Vogtle:
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, Alabama Power’s decommissioning costs are based on the site study and Georgia Power’s decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities as of 2006. The estimates used in current rates are $450 million and $313 million for Plants Hatch and Vogtle, respectively. Amounts expensed were $7 million annually for Plant Vogtle for 2005 through 2007. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and 2.9% for
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Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0% and 4.9% for Alabama Power and Georgia Power, respectively. As a result of license extensions, amounts previously contributed to the external trust funds for Plants Hatch and Farley are currently projected to be adequate to meet the decommissioning obligations. Georgia Power filed an application with the NRC in June 2007 to extend the licenses for Plant Vogtle Units 1 and 2 for an additional 20 years. Georgia Power anticipates the NRC may make a decision regarding the license extension for Plant Vogtle as early as 2009.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized
In accordance with regulatory treatment, the traditional operating companies record AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. The equity component of AFUDC is not included in calculating taxable income. Interest related to the construction of new facilities not included in the traditional operating companies’ regulated rates is capitalized in accordance with standard interest capitalization requirements. AFUDC and interest capitalized, net of income taxes were 8.4%, 4.2%, and 4.0% of net income for 2007, 2006, and 2005, respectively.
Cash payments for interest totaled $798 million, $875 million, and $661 million in 2007, 2006, and 2005, respectively, net of amounts capitalized of $64 million, $27 million, and $21 million, respectively.
Impairment of Long-Lived Assets and Intangibles
Southern 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.
Storm Damage Reserves
Each traditional operating company maintains a reserve to cover the cost of damages from major storms to its transmission and distribution lines and generally the cost of uninsured damages to its generation facilities and other property. In accordance with their respective state PSC orders, the traditional operating companies accrued $25.6 million in 2007 that is recoverable through rates. Alabama Power, Gulf Power, and Mississippi Power also have discretionary authority from their state PSCs to accrue certain additional amounts as circumstances warrant. In 2007, there were no such accruals. In 2006 and 2005, additional accruals totaled $3 million and $6 million, respectively. See Note 3 under “Storm Damage Cost Recovery” for additional information regarding these reserves following Hurricanes Ivan, Dennis, and Katrina and the deferral of additional costs, as well as additional rate riders or other cost recovery mechanisms which have been or may be approved by the respective state PSCs to recover the deferred costs and accrue reserves for future storms.
Leveraged Leases
Southern Company has several leveraged lease agreements, with terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to
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these investments. The Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows.
Southern Company’s net investment in domestic leveraged leases consists of the following at December 31:
A summary of the components of income from domestic leveraged leases was as follows:
Southern Company’s net investment in international leveraged leases consists of the following at December 31:
A summary of the components of income from international leveraged leases was as follows:
See Note 3 under “Income Tax Matters” for additional information regarding the leveraged lease transactions.
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.
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Materials and Supplies
Generally, materials and supplies include the average costs of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
Fuel Inventory
Fuel inventory includes the average costs of oil, coal, natural gas, and emission allowances. Fuel is charged to inventory when purchased and then expensed as used and recovered by the traditional operating companies through fuel cost recovery rates approved by each state PSC. Emission allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.
Stock Options
Prior to January 1, 2006, Southern Company accounted for options granted in accordance with Accounting Principles Board Opinion No. 25; thus, no compensation expense was recognized because the exercise price of all options granted equaled the fair market value on the date of the grant.
Effective January 1, 2006, the Company adopted the fair value recognition provisions of FASB Statement No. 123(R), “Share-Based Payment” (SFAS No. 123(R)), using the modified prospective method. Under that method, compensation cost for the years ended December 31, 2007 and 2006 was recognized as the requisite service was rendered and included: (a) compensation cost for the portion of share-based awards granted prior to and that were outstanding as of January 1, 2006, for which the requisite service had not been rendered, based on the grant-date fair value of those awards as calculated in accordance with the original provisions of FASB Statement No. 123, “Accounting for Stock-Based Compensation”, and (b) compensation cost for all share-based awards granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123(R). Results for prior periods have not been restated.
For Southern Company, the adoption of SFAS No. 123(R) resulted in a reduction in earnings before income taxes and net income of $28 million and $17 million, respectively, for the year ended December 31, 2007, and $28 million and $17 million, respectively, for the year ended December 31, 2006. Additionally, SFAS No. 123(R) requires the gross excess tax benefit from stock option exercises to be reclassified as a financing cash flow as opposed to an operating cash flow; the reduction in operating cash flows and increase in financing cash flows for the years ended December 31, 2007 and 2006 was $21 million and $10 million, respectively.
The adoption of SFAS No. 123(R) also resulted in a reduction in basic and diluted earnings per share of $0.03 and $0.02, respectively, for the year ended December 31, 2007 and $0.02 and $0.03, respectively, for the year ended December 31, 2006.
For the year ended December 31, 2005, prior to the adoption of SFAS No. 123(R), the pro forma impact of fair-value accounting for options granted on net income and basic and diluted earnings per share was as follows:
Because historical forfeitures have been insignificant and are expected to remain insignificant, no forfeitures were assumed in the calculation of compensation expense; rather they are recognized when they occur.
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The estimated fair values of stock options granted in 2007, 2006, and 2005 were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company’s stock over a period equal to the expected term. Southern Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted:
Financial Instruments
Southern Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (categorized in “Other”) and are measured at fair value. Substantially all of Southern Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are exempt from fair value accounting requirements and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the traditional operating companies’ fuel hedging programs. This results in the deferral of related gains and losses in other comprehensive income or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts, including derivatives related to synthetic fuel investments, are marked to market through current period income and are recorded on a net basis in the statements of income.
Southern Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk.
The other Southern Company financial instruments for which the carrying amount did not equal fair value at December 31 were as follows:
The fair values were based on either closing market prices or closing prices of comparable instruments.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, and certain changes in pension and other post retirement benefit plans, less income taxes and reclassifications for amounts included in net income.
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Variable Interest Entities
The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. Southern Company has established certain wholly-owned trusts to issue preferred securities. See Note 6 under “Long-Term Debt Payable to Affiliated Trusts” for additional information. However, Southern Company and the traditional operating companies are not considered the primary beneficiaries of the trusts. Therefore, the investments in these trusts are reflected as Other Investments, and the related loans from the trusts are included in Long-term Debt in the balance sheets.
In addition, Southern Company holds an 85% limited partnership investment in an energy/technology venture capital fund that is consolidated in the financial statements. During the third quarter of 2004, Southern Company terminated new investments in this fund; however, additional contributions to existing investments will still occur. Southern Company has committed to a maximum investment of $46 million, of which $44 million has been funded. Southern Company’s investment in the fund at December 31, 2007 totaled $26.4 million.
2. RETIREMENT BENEFITS
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the plan are expected for the year ending December 31, 2008. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related trusts to the extent required by their respective regulatory commissions. For the year ending December 31, 2008, postretirement trust contributions are expected to total approximately $46 million.
The measurement date for plan assets and obligations is September 30 for each year presented. Pursuant to FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” Southern Company will be required to change the measurement date for its defined benefit postretirement plans from September 30 to December 31 beginning with the year ending December 31, 2008.
Pension Plans
The total accumulated benefit obligation for the pension plans was $5.3 billion in 2007 and $5.1 billion in 2006. Changes during the year in the projected benefit obligations and fair value of plan assets were as follows:
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At December 31, 2007, the projected benefit obligations for the qualified and non-qualified pension plans were $5.3 billion and $0.4 billion, respectively. All plan assets are related to the qualified pension plan.
Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk. The actual composition of the Company’s pension plan assets as of the end of the year, along with the targeted mix of assets, is presented below:
Amounts recognized in the consolidated balance sheets related to the Company’s pension plans consist of the following:
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Presented below are the amounts included in accumulated other comprehensive income, regulatory assets, and regulatory liabilities at December 31, 2007 and December 31, 2006 related to the defined benefit pension plans that have not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for the next fiscal year:
The components of other comprehensive income, along with the changes in the balances of regulatory assets and regulatory liabilities, related to the defined benefit pension plans for the year ended December 31, 2007 are presented in the following table:
Components of net periodic pension cost were as follows:
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Net periodic pension cost (income) is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2007, estimated benefit payments were as follows:
Other Postretirement Benefits
Changes during the year in the accumulated postretirement benefit obligations (APBO) and in the fair value of plan assets were as follows:
Other postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk. The actual composition of the Company’s other postretirement benefit plan assets as of the end of the year, along with the targeted mix of assets, is presented below:
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Amounts recognized in the balance sheets related to the Company’s other postretirement benefit plans consist of the following:
Presented below are the amounts included in accumulated other comprehensive income and regulatory assets at December 31, 2007 and December 31, 2006 related to the other postretirement benefit plans that have not yet been recognized in net periodic postretirement benefit cost along with the estimated amortization of such amounts for the next fiscal year.
The components of other comprehensive income, along with the changes in the balance of regulatory assets, related to the other postretirement benefit plans for the year ended December 31, 2007 are presented in the following table:
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Components of the other postretirement benefit plans’ net periodic cost were as follows:
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced Southern Company’s expenses for the years ended December 31, 2007, 2006, and 2005 by approximately $35 million, $39 million, and $26 million, respectively.
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the postretirement plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows:
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 2004 for the 2005 plan year using a discount rate of 5.75%.
The Company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.
An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 9.75% for 2008, decreasing gradually to 5.25% through the year 2015 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2007 as follows:
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Employee Savings Plan
Southern Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution up to 6% of an employee’s base salary. Prior to November 2006, the Company matched employee contributions at a rate of 75% up to 6% of the employee’s base salary. Total matching contributions made to the plan for 2007, 2006, and 2005 were $73 million, $62 million, and $58 million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
Southern Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, Southern Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Southern Company’s financial statements.
Mirant Matters
Mirant Corporation (Mirant) was an energy company with businesses that included independent power projects and energy trading and risk management companies in the U.S. and selected other countries. It was a wholly-owned subsidiary of Southern Company until its initial public offering in October 2000. In April 2001, Southern Company completed a spin-off to its shareholders of its remaining ownership, and Mirant became an independent corporate entity.
Mirant Bankruptcy
In July 2003, Mirant and certain of its affiliates filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas. The Bankruptcy Court entered an order confirming Mirant’s plan of reorganization in December 2005, and Mirant announced that this plan became effective in January 2006. As part of the plan, Mirant transferred substantially all of its assets and its restructured debt to a new corporation that adopted the name Mirant Corporation (Reorganized Mirant).
Southern Company has certain contingent liabilities associated with guarantees of contractual commitments made by Mirant’s subsidiaries discussed in Note 7 under “Guarantees” and with various lawsuits related to Mirant discussed below. Also, Southern Company has joint and several liability with Mirant regarding the joint consolidated federal income tax returns through 2001, as discussed in Note 5. In December 2004, as a result of concluding an IRS audit for the tax years 2000 and 2001, Southern Company paid approximately $39 million in additional tax and interest related to Mirant tax items and filed a claim in Mirant’s bankruptcy case for that amount. Through December 2007, Southern Company received from the IRS approximately $36 million in refunds related to Mirant. Southern Company believes it has a right to recoup the $39 million tax payment owed by Mirant from such tax refunds. As a result, Southern Company intends to retain the tax refunds and reduce its claim against Mirant for the payment of Mirant taxes by the amount of such refunds. MC Asset Recovery, a special purpose subsidiary of Reorganized Mirant, has objected to and sought to equitably subordinate the Southern Company tax claim in its fraudulent
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transfer litigation against Southern Company. Southern Company has reserved the approximately $3 million amount remaining with respect to its Mirant tax claim.
Under the terms of the separation agreements entered into in connection with the spin-off, Mirant agreed to indemnify Southern Company for costs associated with these guarantees, lawsuits, and additional IRS assessments. However, as a result of Mirant’s bankruptcy, Southern Company sought reimbursement as an unsecured creditor in Mirant’s Chapter 11 proceeding. As part of a complaint filed against Southern Company in June 2005 and amended thereafter, Mirant and The Official Committee of Unsecured Creditors of Mirant Corporation (Unsecured Creditors’ Committee) objected to and sought equitable subordination of Southern Company’s claims, and Mirant moved to reject the separation agreements entered into in connection with the spin-off. MC Asset Recovery has been substituted as plaintiff in the complaint. If Southern Company’s claims for indemnification with respect to these, or any additional future payments, are allowed, then Mirant’s indemnity obligations to Southern Company would constitute unsecured claims against Mirant entitled to stock in Reorganized Mirant. The final outcome of this matter cannot now be determined.
MC Asset Recovery Litigation
In June 2005, Mirant, as a debtor in possession, and the Unsecured Creditors’ Committee filed a complaint against Southern Company in the U.S. Bankruptcy Court for the Northern District of Texas, which was amended in July 2005, February 2006, May 2006, and March 2007.
In December 2005, the Bankruptcy Court entered an order authorizing the transfer of this proceeding, along with certain other actions, to MC Asset Recovery. Under that order, Reorganized Mirant is obligated to fund up to $20 million in professional fees in connection with the lawsuits, as well as certain additional amounts. Any net recoveries from these lawsuits will be distributed to, and shared equally by, certain unsecured creditors and the original equity holders. In January 2006, the U.S. District Court for the Northern District of Texas substituted MC Asset Recovery as plaintiff.
The complaint, as amended in March 2007, alleges that Southern Company caused Mirant to engage in certain fraudulent transfers and to pay illegal dividends to Southern Company prior to the spin-off. The alleged fraudulent transfers and illegal dividends include without limitation: (1) certain dividends from Mirant to Southern Company in the aggregate amount of $668 million, (2) the repayment of certain intercompany loans and accrued interest in an aggregate amount of $1.035 billion, and (3) the dividend distribution of one share of Series B Preferred Stock and its subsequent redemption in exchange for Mirant’s 80% interest in a holding company that owned SE Finance Capital Corporation and Southern Company Capital Funding, Inc., which transfer plaintiff asserts is valued at over $200 million. The complaint also seeks to recharacterize certain advances from Southern Company to Mirant for investments in energy facilities from debt to equity. The complaint further alleges that Southern Company is liable to Mirant’s creditors for the full amount of Mirant’s liability under an alter ego theory of recovery and that Southern Company breached its fiduciary duties to Mirant and its creditors, caused Mirant to breach its fiduciary duties to creditors, and aided and abetted breaches of fiduciary duties by Mirant’s directors and officers. The complaint also seeks recoveries under the theories of restitution and unjust enrichment. In addition, the complaint alleges a claim under the Federal Debt Collection Procedure Act (FDCPA) to void certain transfers from Mirant to Southern Company. MC Asset Recovery claims to have standing to assert violations of the FDCPA and to recover property on behalf of the Mirant debtors’ estates. The complaint seeks monetary damages in excess of $2 billion plus interest, punitive damages, attorneys’ fees, and costs. Finally, the complaint includes an objection to Southern Company’s pending claims against Mirant in the Bankruptcy Court (which relate to reimbursement under the separation agreements of payments such as income taxes, interest, legal fees, and other guarantees described in Note 7) and seeks equitable subordination of Southern Company’s claims to the claims of all other creditors. Southern Company served an answer to the complaint in April 2007.
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In January 2006, the U.S. District Court for the Northern District of Texas granted Southern Company’s motion to withdraw this action from the Bankruptcy Court and, in February 2006, granted Southern Company’s motion to transfer the case to the U.S. District Court for the Northern District of Georgia. In May 2006, Southern Company filed a motion for summary judgment seeking entry of judgment against the plaintiff as to all counts of the complaint. In December 2006, the U.S. District Court for the Northern District of Georgia granted in part and denied in part the motion. As a result, certain breach of fiduciary duty claims alleged in earlier versions of the complaint are barred; all other claims in the complaint may proceed. Southern Company believes there is no meritorious basis for the claims in the complaint and is vigorously defending itself in this action. However, the final outcome of this matter cannot now be determined.
Mirant Securities Litigation
In November 2002, Southern Company, certain former and current senior officers of Southern Company, and 12 underwriters of Mirant’s initial public offering were added as defendants in a class action lawsuit that several Mirant shareholders originally filed against Mirant and certain Mirant officers in May 2002. Several other similar lawsuits filed subsequently were consolidated into this litigation in the U.S. District Court for the Northern District of Georgia. The amended complaint is based on allegations related to alleged improper energy trading and marketing activities involving the California energy market, alleged false statements and omissions in Mirant’s prospectus for its initial public offering and in subsequent public statements by Mirant, and accounting-related issues previously disclosed by Mirant. The lawsuit purports to include persons who acquired Mirant securities between September 26, 2000 and September 5, 2002.
In July 2003, the court dismissed all claims based on Mirant’s alleged improper energy trading and marketing activities involving the California energy market. The other claims do not allege any improper trading and marketing activity, accounting errors, or material misstatements or omissions on the part of Southern Company but seek to impose liability on Southern Company based on allegations that Southern Company was a “control person” as to Mirant prior to the spin-off date. Southern Company filed an answer to the consolidated amended class action complaint in September 2003. Plaintiffs have also filed a motion for class certification.
During Mirant’s Chapter 11 proceeding, the securities litigation was stayed, with the exception of limited discovery. Since Mirant’s plan of reorganization has become effective, the stay has been lifted. In March 2006, the plaintiffs filed a motion for reconsideration requesting that the court vacate that portion of its July 2003 order dismissing the plaintiffs’ claims based upon Mirant’s alleged improper energy trading and marketing activities involving the California energy market. Southern Company and the other defendants have opposed the plaintiffs’ motion. On March 6, 2007, the court granted plaintiffs’ motion for reconsideration, reinstated the California energy market claims, and granted in part and denied in part defendants’ motion to compel certain class certification discovery. On March 21, 2007, defendants filed renewed motions to dismiss the California energy claims on grounds originally set forth in their 2003 motions to dismiss, but which were not addressed by the court. On July 27, 2007, certain defendants, including Southern Company, filed motions for reconsideration of the court’s denial of a motion seeking dismissal of certain federal securities laws claims based upon, among other things, certain alleged errors included in financial statements issued by Mirant. The ultimate outcome of this matter cannot be determined at this time.
The plaintiffs have also stated that they intend to request that the court grant leave for them to amend the complaint to add allegations based upon claims asserted against Southern Company in the MC Asset Recovery litigation.
Under certain circumstances, Southern Company will be obligated under its Bylaws to indemnify the four current and/or former Southern Company officers who served as directors of Mirant at the time of its initial public offering through the date of the spin-off and who are also named as defendants in this lawsuit. The final outcome of this matter cannot now be determined.
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Environmental Matters
New Source Review Actions
In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama after Alabama Power was dismissed from the original action. In these lawsuits, the EPA alleged that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The action against Georgia Power has been administratively closed since the spring of 2001, and the case has not been reopened.
In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving the alleged NSR violations at Plant Miller. The consent decree required Alabama Power to pay $100,000 to resolve the government’s claim for a civil penalty and to donate $4.9 million of sulfur dioxide emission allowances to a nonprofit charitable organization and formalized specific emissions reductions to be accomplished by Alabama Power, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in Alabama granted Alabama Power’s motion for summary judgment and entered final judgment in favor of Alabama Power on the EPA’s claims related to all of the remaining plants: Plants Barry, Gaston, Gorgas, and Greene County.
The plaintiffs appealed the district court’s decision to the U.S. Court of Appeals for the Eleventh Circuit, and the appeal was stayed by the Appeals Court pending the U.S. Supreme Court’s decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke Energy case in April 2007. On October 5, 2007, the U.S. District Court for the Northern District of Alabama issued an order in the Alabama Power case indicating a willingness to re-evaluate its previous decision in light of the Supreme Court’s Duke Energy opinion. On December 21, 2007, the Eleventh Circuit vacated the district court’s decision in the Alabama Power case and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court’s decision in the Duke Energy case. The final outcome of these matters cannot be determined at this time.
Southern Company believes that the traditional operating companies complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in either of these cases could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
Carbon Dioxide Litigation
In July 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each
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year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and no decision has been issued. The ultimate outcome of these matters cannot be determined at this time.
Environmental Remediation
Southern Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the subsidiaries may also incur substantial costs to clean up properties. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. Within limits approved by the state PSCs, these rates are adjusted annually or as necessary.
Through 2007, Georgia Power recovered environmental costs through its base rates. Beginning in 2008, in connection with the retail rate plan for the years 2008 through 2010 (2007 Retail Rate Plan), an environmental compliance cost recovery tariff, including an annual accrual of $1.2 million for environmental remediation, was implemented. Environmental remediation expenditures will be charged against the reserve as they are incurred. The annual accrual amount will be reviewed and adjusted as necessary in future regulatory proceedings. The balance of Georgia Power’s environmental remediation liability at December 31, 2007 was $13.5 million.
Georgia Power has been designated as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a large site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites on the Georgia Hazardous Sites Inventory and CERCLA NPL are anticipated.
Gulf Power’s environmental remediation liability includes estimated costs of environmental remediation projects of approximately $66.9 million as of December 31, 2007. These estimated costs relate to new regulations and more stringent site closure criteria by the Florida Department of Environmental Protection (FDEP) for impacts to groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects will be subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power’s environmental cost recovery clause; therefore, there was no impact on net income as a result of these estimates.
The final outcome of these matters cannot now be determined. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management does not believe that additional liabilities, if any, at these sites would be material to the financial statements.
FERC Matters
Market-Based Rate Authority
Each of the traditional operating companies and Southern Power has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.
In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding.
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Any new market-based rate sales by any subsidiary of Southern Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level.
In late June and July 2007, hearings were held in this proceeding and the presiding administrative law judge issued an initial decision on November 9, 2007 regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the traditional operating companies and Southern Power to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates and could also result in refunds of up to $19.7 million, plus interest. Southern Company and its subsidiaries believe that there is no meritorious basis for this proceeding and are vigorously defending themselves in this matter.
On June 21, 2007, the FERC issued its final rule regarding market-based rate authority. The FERC generally retained its current market-based rate standards. The impact of this order and its effect on the generation dominance proceeding cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet in its retail service territory is operated under the Intercompany Interchange Contract (IIC), as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct.
In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms and Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. Southern Company filed with the FERC in November 2006 a compliance plan in connection with the order. On April 19, 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan is not expected to have a material impact on the Company’s financial statements. On November 19, 2007, Southern Company notified the FERC that the plan had been implemented and the FERC division of audits subsequently began an audit pertaining to compliance implementation and related matters, which is ongoing.
Generation Interconnection Agreements
In November 2004, generator company subsidiaries of Tenaska, Inc. (Tenaska), as counterparties to three previously executed interconnection agreements with subsidiaries of Southern Company, filed complaints at the FERC requesting that the FERC modify the agreements and that those Southern Company subsidiaries refund a total of $19 million previously paid for interconnection facilities. No other similar complaints are pending with the FERC.
On January 19, 2007, the FERC issued an order granting Tenaska’s requested relief. Although the FERC’s order required the modification of Tenaska’s interconnection agreements, under the provisions of the order, Southern Company determined that no refund was payable to Tenaska. Southern Company requested rehearing asserting that the FERC retroactively applied a new principle to existing interconnection agreements. Tenaska requested rehearing of FERC’s methodology for determining the amount of refunds. The requested rehearings were denied, and
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Southern Company and Tenaska have appealed the orders to the U.S. Circuit Court for the District of Columbia. The final outcome of this matter cannot now be determined.
Right of Way Litigation
Southern Company and certain of its subsidiaries, including Gulf Power, Mississippi Power, and Southern Telecom, Inc. (a subsidiary of SouthernLINC Wireless), have been named as defendants in numerous lawsuits brought by landowners since 2001. The plaintiffs’ lawsuits claim that defendants may not use, or sublease to third parties, some or all of the fiber optic communications lines on the rights of way that cross the plaintiffs’ properties and that such actions exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment and seek compensatory and punitive damages and injunctive relief. Management of Southern Company and its subsidiaries believe that they have complied with applicable laws and that the plaintiffs’ claims are without merit.
In November 2003, the Second Circuit Court in Gadsden County, Florida, ruled in favor of the plaintiffs on their motion for partial summary judgment concerning liability in one such lawsuit brought by landowners regarding the installation and use of fiber optic cable over Gulf Power rights of way located on the landowners’ property. Subsequently, the plaintiffs sought to amend their complaint and asked the court to enter a final declaratory judgment and to enter an order enjoining Gulf Power from allowing expanded general telecommunications use of the fiber optic cables that are the subject of this litigation. In January 2005, the trial court granted in part the plaintiffs’ motion to amend their complaint and denied the requested declaratory and injunctive relief. In November 2005, the trial court ruled in favor of the plaintiffs and against Gulf Power on their respective motions for partial summary judgment. In that same order, the trial court also denied Gulf Power’s motion to dismiss certain claims. Gulf Power filed an appeal to the Florida First District Court of Appeals in December 2005. In October 2006, the Florida First District Court of Appeal issued an order dismissing Gulf Power’s December 2005 appeal on the basis that the trial court’s order was a non-final order and therefore not subject to review on appeal at this time. The case was returned to the trial court for further proceedings. The parties reached agreement on a proposed settlement plan that was subject to approval by the trial court. On November 7, 2007, the trial court granted preliminary approval and set forth the requirements for the trial court to make its final determination on the proposed settlement. Although the final outcome of this matter cannot now be determined, if approved the settlement is not expected to have a material effect on Southern Company’s financial statements.
To date, Mississippi Power has entered into agreements with plaintiffs in approximately 90% of the actions pending against Mississippi Power to clarify its easement rights in the State of Mississippi. These agreements have been approved by the Circuit Courts of Harrison County and Jasper County, Mississippi (First Judicial Circuit), and dismissals of the related cases are in progress. These agreements have not resulted in any material effects on Southern Company’s financial statements.
In addition, in late 2001, certain subsidiaries of Southern Company, including Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Telecom, Inc. (a subsidiary of SouthernLINC Wireless), were named as defendants in a lawsuit brought by a telecommunications company that uses certain of the defendants’ rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. The Company believes that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. An adverse outcome in this matter, combined with an adverse outcome against the telecommunications company in one or more of the right of way lawsuits, could result in substantial judgments; however, the final outcome of these matters cannot now be determined.
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Income Tax Matters
Leveraged Leases
Southern Company undergoes audits by the IRS for each of its tax years. The IRS has completed its audits of Southern Company’s consolidated federal income tax returns for all years prior to 2004. The IRS challenged Southern Company’s deductions related to three international lease transactions (SILO or sale-in-lease-out transactions), in connection with its audits of Southern Company’s 2000 through 2003 tax returns. In the third quarter 2006, Southern Company paid the full amount of the disputed tax and the applicable interest on the SILO issue for tax years 2000 and 2001 and filed a claim for refund which was denied by the IRS. The disputed tax amount was $79 million and the related interest approximately $24 million for these tax years. This payment, and the subsequent IRS disallowance of the refund claim, closed the issue with the IRS and Southern Company has initiated litigation in the U.S. District Court for the Northern District of Georgia for a complete refund of tax and interest paid for the 2000 and 2001 tax years. The IRS also challenged the SILO deductions for the tax years 2002 and 2003. The estimated amount of disputed tax and interest for tax years 2002 and 2003 was approximately $83 million and $15 million, respectively. The tax and interest for these tax years was paid to the IRS in the fourth quarter 2006. Southern Company has accounted for both payments in 2006 as deposits. For tax years 2000 through 2007, Southern Company has claimed approximately $330 million in tax benefits related to these SILO transactions challenged by the IRS. These tax benefits relate to timing differences and do not impact total net income. Southern Company believes these transactions are valid leases for U.S. tax purposes and the related deductions are allowable. Southern Company is continuing to pursue resolution of these matters; however, the ultimate outcome cannot now be determined. In addition, the U.S. Senate is currently considering legislation that would disallow tax benefits for SILO losses and other international leveraged lease transactions (such as lease-in-lease-out transactions) occurring after December 31, 2007. The ultimate impact on Southern Company’s net income and cash flow will be dependent on the outcome of pending litigation and proposed legislation, but could be significant, and potentially material.
Effective January 1, 2007, Southern Company adopted both FIN 48 and FASB Staff Position No. FAS 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction” (FSP 13-2). FIN 48 requires companies to determine whether it is “more likely than not” that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. It also provides guidance on the recognition, measurement, and classification of income tax uncertainties, along with any related interest and penalties. FSP 13-2 amends FASB Statement No. 13, “Accounting for Leases” requiring recalculation of the rate of return and the allocation of income whenever the projected timing of the income tax cash flows generated by a leveraged lease is revised with recognition of the resulting gain or loss in the year of the revision. FSP 13-2 also requires that all recognized tax positions in a leveraged lease must be measured in accordance with the criteria in FIN 48 and any changes resulting from FIN 48 must be reflected as a change in an important lease assumption as of the date of adoption. In adopting these standards, Southern Company concluded that a portion of the SILO tax benefits were uncertain tax positions, as defined in FIN 48. Accordingly, Southern Company also concluded that there was a change in the timing of project income tax cash flows and, as required by FSP 13-2, recalculated the rate of return and allocation of income under the lease-in-lease-out (LILO) and SILO transactions.
The cumulative effect of the initial adoption of FIN 48 and FSP 13-2 was recorded as an adjustment to beginning retained earnings. For the LILO transaction settled with the IRS in February 2005, the cumulative effect of adopting FSP 13-2 was a $17 million reduction in beginning retained earnings. With respect to Southern Company’s SILO transactions, the adoption of FSP 13-2 reduced beginning retained earnings by $108 million and the adoption of FIN 48 reduced beginning retained earnings by an additional $15 million. The adjustments to retained earnings are non-cash charges and those related to FSP 13-2 will be recognized as income over the remaining terms of the affected leases. The adoption of FSP 13-2 also resulted in a reduction of net income of approximately $15 million during 2007. Any future changes in the projected or actual income tax cash flows will result in an additional recalculation of the net investment in the leases and will be recorded currently in income.
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Georgia State Income Tax Credits
Georgia Power’s 2005 through 2007 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. Georgia Power has also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue has not responded to these claims. On July 24, 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. If Georgia Power prevails, these claims could have a significant, and possibly material, positive effect on Southern Company’s net income. If Georgia Power is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on Southern Company’s cash flow. The ultimate outcome of this matter cannot now be determined.
Alabama Power Retail Regulatory Matters
Alabama Power operates under a Rate Stabilization and Equalization Plan (Rate RSE) approved by the Alabama PSC. Prior to 2007, Rate RSE provided for periodic annual adjustments based upon Alabama Power’s earned return on end-of-period retail common equity. Beginning in 2007, Rate RSE adjustments are effective in January based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4% per year and any annual adjustment is limited to 5%. Rates remain unchanged when the retail return on common equity (ROE) is projected to be between 13% and 14.5%. If Alabama Power’s actual retail ROE is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return on common equity fall below the allowed equity return range. The Rate RSE increase for 2007 was 4.76%, or $193 million annually. The ratemaking procedures will remain in effect until the Alabama PSC votes to modify or discontinue them.
The Alabama PSC has also approved a rate mechanism that provides for adjustments to recognize the cost of placing new generating facilities in retail service and for the recovery of retail costs associated with certificated purchased power agreements (Rate CNP). In April 2005, an adjustment to Rate CNP decreased retail rates by approximately 0.5%, or $19 million annually. The annual true-up adjustment effective in April 2006 increased retail rates by 0.5%, or $19 million annually. In April 2007, there was no adjustment to Rate CNP.
In October 2004, the Alabama PSC approved a request by Alabama Power to amend Rate CNP to also provide for the recovery of retail costs associated with environmental laws and regulations, effective in January 2005. The rate mechanism began operation in January 2005 and provides for the recovery of these costs pursuant to a factor that will be calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on invested capital. Retail rates increased approximately 1.2% in January 2006 and 0.6% in January 2007.
Alabama Power fuel costs are recovered under Rate ECR (Energy Cost Recovery), which provides for the addition of a fuel and energy cost factor to base rates. In June 2007, the Alabama PSC approved Alabama Power’s request to increase the retail energy cost recovery rate to 3.100 cents per kilowatt hour, effective with billings beginning July 2007 for the 30-month period ending December 2009. As of December 31, 2007, Alabama Power had an under recovered fuel balance of approximately $280 million, of which approximately $82 million is included in deferred charges and other assets in the balance sheets.
Georgia Power Retail Regulatory Matters
In December 2007, the Georgia PSC approved the 2007 Retail Rate Plan. Under the 2007 Retail Rate Plan, Georgia Power’s earnings will continue to be evaluated against a retail ROE range of 10.25% to 12.25%. Two-thirds of any earnings above 12.25% will be applied to rate refunds with the remaining one-third applied to an environmental compliance cost recovery (ECCR) tariff. Georgia Power has agreed that it will not file for a general base rate increase during this period unless its projected retail ROE falls below 10.25%. Retail base rates increased by
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approximately $99.7 million effective January 1, 2008 to provide for cost recovery of transmission, distribution, generation, and other investments, as well as increased operating costs. In addition, the ECCR tariff was implemented to allow for the recovery of costs for required environmental projects mandated by state and federal regulations. The ECCR tariff increased rates by approximately $222 million effective January 1, 2008. Georgia Power is required to file a general rate case by July 1, 2010, in response to which the Georgia PSC would be expected to determine whether the 2007 Retail Rate Plan should be continued, modified, or discontinued.
In December 2004, the Georgia PSC approved the retail rate plan for the years 2005 through 2007 (2004 Retail Rate Plan) for Georgia Power. Under the terms of the 2004 Retail Rate Plan, Georgia Power’s earnings were evaluated against a retail ROE range of 10.25% to 12.25%. Two-thirds of any earnings above 12.25% were applied to rate refunds, with the remaining one-third retained by Georgia Power. Retail rates and customer fees increased by approximately $203 million effective January 1, 2005 to cover the higher costs of purchased power, operating and maintenance expenses, environmental compliance, and continued investment in new generation, transmission, and distribution facilities to support growth and ensure reliability. In 2007, Georgia Power refunded 2005 earnings above 12.25% retail ROE. There were no refunds related to earnings for 2006 or 2007.
Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. On February 6, 2007, the Georgia PSC approved an increase in Georgia Power’s total annual billings of approximately $383 million effective March 1, 2007. The Georgia PSC order reduced Georgia Power’s requested increase in the forecast of annual fuel costs by $40 million and disallowed $4 million of previously incurred fuel costs. As of December 31, 2007, Georgia Power had an under recovered fuel balance of approximately $692 million, of which approximately $307 million is included in deferred charges and other assets in the balance sheets. The Georgia PSC order also requires Georgia Power to file for a new fuel cost recovery rate no later than March 1, 2008.
Storm Damage Cost Recovery
Each traditional operating company maintains a reserve to cover the cost of damages from major storms to its transmission and distribution lines and generally the cost of uninsured damages to its generation facilities and other property. In addition, each traditional operating company affected by recent hurricanes has been authorized by its state PSC to defer the portion of the hurricane restoration costs that exceeded the balance in its storm damage reserve account. As of December 31, 2007, the under recovered balance in Southern Company’s storm damage reserve accounts totaled approximately $43 million, of which approximately $40 million and $3 million, respectively, are included in the balance sheets herein under “Other Current Assets” and “Other Regulatory Assets.”
In June 2006, the Mississippi PSC issued an order that certified actual storm restoration costs relating to Hurricane Katrina through April 30, 2006 of $267.9 million and affirmed estimated additional costs through December 31, 2007 of $34.5 million, for total storm restoration costs of $302.4 million which was net of insurance proceeds of approximately $77 million, without offset for the property damage reserve of $3.0 million. Of the total amount, $292.8 million applies to Mississippi Power’s retail jurisdiction. The order directed Mississippi Power to file an application with the Mississippi Development Authority (MDA) for a Community Development Block Grant (CDBG). In October 2006, Mississippi Power received from the MDA a CDBG in the amount of $276.4 million. Mississippi Power has appropriately allocated and applied these CDBG proceeds to both retail and wholesale storm restoration cost recovery.
In October 2006, the Mississippi PSC issued a financing order that authorized the issuance of $121.2 million of system restoration bonds. This amount includes $25.2 million for the retail storm recovery costs not covered by the CDBG, $60 million for a property damage reserve, and $36 million for the retail portion of the construction of the storm operations facility. The bonds were issued by the Mississippi Development Bank on behalf of the State of Mississippi on June 1, 2007.
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On June 1, 2007, Mississippi Power received a grant payment of $85.2 million from the State of Mississippi representing recovery of $25.2 million in retail storm restoration costs incurred or to be incurred and $60.0 million to increase Mississippi Power’s property damage reserve. In the fourth quarter 2007, Mississippi Power received additional grant payments of $24.1 million for expenditures incurred for construction of a new storm operations center. The funds received related to previously incurred storm restoration expenditures have been accounted for as a government grant and have been recorded as a reduction to the regulatory asset that was recorded as the storm restoration expenditures were incurred. The funds received for storm restoration expenditures to be incurred were recorded as a regulatory liability. Mississippi Power will receive further grant payments of up to $11.9 million as expenditures are incurred to construct the new storm operations center. As of December 31, 2007, Mississippi Power had no under recovered balance in the property damage reserve account.
In July 2006, the Florida PSC issued its order approving a stipulation and settlement between Gulf Power and several consumer groups that resolved all matters relating to Gulf Power’s request for recovery of incurred costs for storm-recovery activities and the replenishment of Gulf Power’s property damage reserve. The order provided for an extension of the storm-recovery surcharge then being collected by Gulf Power for an additional 27 months, expiring in June 2009. According to the stipulation, the funds resulting from the extension of the surcharge were first credited to the unrecovered balance of storm-recovery costs associated with Hurricane Ivan until these costs were fully recovered. The funds are now being credited to the property reserve for recovery of the storm-recovery costs of $52.6 million associated with Hurricanes Dennis and Katrina that were previously charged to the reserve. Should revenues collected by Gulf Power through the extension of the storm-recovery surcharge exceed the storm-recovery costs associated with Hurricanes Dennis and Katrina, the excess revenues will be credited to the reserve. The annual accrual to the reserve of $3.5 million and Gulf Power’s limited discretionary authority to make additional accruals to the reserve will continue as previously approved by the Florida PSC. Gulf Power made discretionary accruals to the reserve of $3 million and $6 million in 2006 and 2005, respectively. Gulf Power made no discretionary accrual to the reserve in 2007. According to the order, in the case of future storms, if Gulf Power incurs cumulative costs for storm-recovery activities in excess of $10 million during any calendar year, Gulf Power will be permitted to file a streamlined formal request for an interim surcharge. Any interim surcharge would provide for the recovery, subject to refund, of up to 80% of the claimed costs for storm-recovery activities. Gulf Power would then petition the Florida PSC for full recovery through an additional surcharge or other cost recovery mechanism.
As of December 31, 2007, Gulf Power’s unrecovered balance in the property damage reserve totaled approximately $18.6 million which is included in the balance sheets under “Current Assets.”
At Alabama Power, expenses associated with Hurricane Ivan were $57.8 million. In 2005, Alabama Power received Alabama PSC approvals to return certain regulatory liabilities to the retail customers. These orders also allowed Alabama Power to simultaneously recover from customers accruals of approximately $48 million primarily to offset the costs of Hurricane Ivan and restore a positive balance in the natural disaster reserve (NDR). The combined effect of these orders had no impact on net income in 2005.
In December 2005, the Alabama PSC approved a separate rate rider to recover Alabama Power’s $51 million of deferred Hurricane Dennis and Katrina storm restoration costs over a two-year period and to replenish its reserve to a target balance of $75 million over a five-year period.
In June 2007, Alabama Power fully recovered its prior storm cost of $51 million resulting from Hurricanes Dennis and Katrina. As a result, customer rates decreased by this portion of the NDR charge effective in July 2007. At December 31, 2007, Alabama Power had accumulated a balance of $26.1 million in the target reserve for future storms, which is included in the balance sheets under “Other Regulatory Liabilities.”
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Kemper County Integrated Coal Gasification Combined Cycle
In June 2006, Mississippi Power filed an application with the DOE for certain tax credits available to projects using clean coal technologies under the Energy Policy Act of 2005. The proposed project is an advanced coal gasification facility located in Kemper County, Mississippi that would use locally mined lignite coal. The proposed 693-megawatt plant, excluding the mine cost, is expected to require an approximate investment of $1.5 billion and is expected to be completed in 2013. The DOE subsequently certified the project and in November 2006 the IRS allocated Internal Revenue Code tax credits to Mississippi Power of $133 million. The utilization of these credits is dependent upon meeting the certification requirements for the project under the Internal Revenue Code. The plant would use an air-blown integrated gasification combined cycle technology that generates power from low-rank coals and coals with high moisture or high ash content. These coals, which include lignite, make up half the proven U.S. and worldwide coal reserves. Mississippi Power is undertaking a feasibility assessment of the project which could take up to two years. Approval by various regulatory agencies, including the Mississippi PSC, will also be required if the project proceeds. The Mississippi PSC has authorized Mississippi Power to create a regulatory asset for the approved retail portion of the costs associated with the generation resource planning, evaluation, and screening activities up to approximately $23.8 million ($16 million for the retail portion). The retail portion of these costs will be charged to and remain as a regulatory asset until the Mississippi PSC determines the prudence and ultimate recovery, which decision is expected in January 2009. The final outcome of this matter cannot now be determined.
4. JOINT OWNERSHIP AGREEMENTS
Alabama Power owns an undivided interest in units 1 and 2 of Plant Miller and related facilities jointly with Alabama Electric Cooperative, Inc. Georgia Power owns undivided interests in Plants Vogtle, Hatch, Scherer, and Wansley in varying amounts jointly with Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia, the city of Dalton, Georgia, Florida Power & Light Company, and Jacksonville Electric Authority. In addition, Georgia Power has joint ownership agreements with OPC for the Rocky Mountain facilities and with Florida Power Corporation for a combustion turbine unit at Intercession City, Florida. Southern Power owns an undivided interest in Plant Stanton Unit A and related facilities jointly with the Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency.
At December 31, 2007, Alabama Power’s, Georgia Power’s, and Southern Power’s ownership and investment (exclusive of nuclear fuel) in jointly owned facilities with the above entities were as follows:
At December 31, 2007, the portion of total construction work in progress related to Plants Miller, Scherer, Wansley, and Rocky Mountain was $49.1 million, $66.5 million, $170.3 million, and $4.0 million, respectively, primarily for environmental projects.
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Alabama Power, Georgia Power, and Southern Power have contracted to operate and maintain the jointly owned facilities, except for Rocky Mountain and Intercession City, as agents for their respective co-owners. The companies’ proportionate share of their plant operating expenses is included in the corresponding operating expenses in the statements of income.
5. INCOME TAXES
Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Alabama, Georgia, and Mississippi. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability.
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
Net cash payments for income taxes in 2007, 2006, and 2005 were $732 million, $649 million, and $100 million, respectively.
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:
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At December 31, 2007, Southern Company had a State of Georgia net operating loss (NOL) carryforward totaling $1.0 billion, which could result in net state income tax benefits of $59 million, if utilized. However, Southern Company has established a valuation allowance for the potential $59 million tax benefit due to the remote likelihood that the tax benefit will be realized. These NOLs will expire between 2008 and 2021. During 2007, Southern Company utilized $0.8 million in available NOLs, which resulted in a $0.05 million state income tax benefit. The State of Georgia allows the filing of a combined return, which should substantially reduce any additional NOL carryforwards.
At December 31, 2007, the tax-related regulatory assets and liabilities were $911 million and $275 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest. These liabilities are attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized investment tax credits.
In accordance with regulatory requirements, deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $23 million in 2007, $23 million in 2006, and $25 million in 2005. At December 31, 2007, all investment tax credits available to reduce federal income taxes payable had been utilized.
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Effective Tax Rate
The provision for income taxes differs from the amount of income taxes determined by applying the applicable U.S. federal statutory rate to earnings before income taxes and preferred and preference dividends of subsidiaries, as a result of the following:
The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to United States production activities as defined in Internal Revenue Code Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for years 2007 through 2009, and a 9% rate applicable for all years after 2009. This increase from 3% in 2006 to 6% in 2007 was one of several factors that increased Southern Company’s 2007 deduction by $32 million over the 2006 deduction. The resulting additional tax benefit was $11 million.
In 2007, Georgia Power donated 2,200 acres of land in the Tallulah Gorge State Park to the State of Georgia. The estimated value of the donation caused a lower effective income tax rate for the year ended December 31, 2007, when compared to December 31, 2006.
Unrecognized Tax Benefits
On January 1, 2007, Southern Company adopted FIN 48, which requires companies to determine whether it is “more likely than not” that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. It also provides guidance on the recognition, measurement, and classification of income tax uncertainties, along with any related interest and penalties.
Prior to the adoption of FIN 48, Southern Company had unrecognized tax benefits which were previously accrued under Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies” of approximately $65 million. Upon adoption of FIN 48, an additional $146 million of unrecognized tax benefits were recorded, which resulted in a total balance of $211 million. The $146 million relates to tax positions for which ultimate deductibility is highly certain, but for which there is uncertainty as to the timing of such deductibility. For 2007, the total amount of unrecognized tax benefits increased by $53 million, resulting in a balance of $264 million as of December 31, 2007.
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Changes during the year in unrecognized tax benefits were as follows:
Impact on Southern Company’s effective tax rate, if recognized, is as follows:
Accrued interest for unrecognized tax benefits:
Southern Company classifies interest on tax uncertainties as interest expense. The net amount of interest accrued as of adoption of FIN 48 was $27 million, which resulted in a reduction to beginning 2007 retained earnings of approximately $15 million, net of tax. Net interest accrued for the year ended December 31, 2007 was $4 million. Southern Company did not accrue any penalties on uncertain tax positions.
The IRS has audited and closed all tax returns prior to 2004. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2002.
It is reasonably possible that the amount of the unrecognized benefit with respect to certain of Southern Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The possible settlement of the SILO litigation, the Georgia state tax credits litigation, the production activities deduction methodology, and/or the conclusion or settlement of federal or state audits could impact the balances significantly. At this time, other than the SILO litigation, an estimate of the range of reasonably possible outcomes cannot be determined. The unrecognized benefit related to the SILO litigation could decrease by $165 million within the next 12 months. See Note 3 under “Income Tax Matters” for additional information.
6. FINANCING
Long-Term Debt Payable to Affiliated Trusts
Southern Company and certain of the traditional operating companies have formed certain wholly-owned trust subsidiaries for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to Southern Company or the applicable traditional operating company through the issuance of junior subordinated notes totaling $412 million, which constitute substantially all of the
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assets of these trusts and are reflected in the balance sheets as “Long-term Debt.” Southern Company and such traditional operating companies each consider that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective trusts’ payment obligations with respect to these securities. At December 31, 2007, preferred securities of $400 million were outstanding. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities.
Securities Due Within One Year
A summary of scheduled maturities and redemptions of securities due within one year at December 31 was as follows:
Debt and preferred stock redemptions, and/or serial maturities through 2012 applicable to total long-term debt are as follows: $1.2 billion in 2008; $609 million in 2009; $291 million in 2010; $332 million in 2011; and $1.6 billion in 2012.
Assets Subject to Lien
Each of Southern Company’s subsidiaries is organized as a legal entity, separate and apart from Southern Company and its other subsidiaries. Alabama Power and Gulf Power have granted one or more liens on certain of their respective property in connection with the issuance of certain pollution control bonds with an outstanding principal amount of $194 million. There are no agreements or other arrangements among the subsidiary 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 the beginning of 2008, unused credit arrangements with banks totaled $4.1 billion, of which $811 million expires during 2008 and $3.3 billion expires in 2012. The following table outlines the credit arrangements by company:
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Approximately $79 million of the credit facilities expiring in 2008 allow the execution of term loans for an additional two-year period and $500 million allow execution of one-year term loans. Most of these agreements include stated borrowing rates.
All of the credit arrangements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees are one-eighth of 1% or less for Southern Company, the traditional operating companies, and Southern Power. Compensating balances are not legally restricted from withdrawal.
Most of the credit arrangements with banks have covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts and, in certain arrangements, other hybrid securities. At December 31, 2007, Southern Company, Southern Power, and the traditional operating companies were each in compliance with their respective debt limit covenants.
In addition, the credit arrangements typically contain cross default provisions that would be triggered if the borrower defaulted on other indebtedness above a specified threshold. The cross default provisions are restricted only to the indebtedness, including any guarantee obligations, of the company that has such credit arrangements. Southern Company and its subsidiaries are currently in compliance with all such covenants.
A portion of the $4.1 billion unused credit with banks is allocated to provide liquidity support to the traditional operating companies’ variable rate pollution control bonds. The amount of variable rate pollution control bonds requiring liquidity support as of December 31, 2007 was $927 million.
Southern Company, the traditional operating companies, and Southern Power borrow primarily through commercial paper programs that have the liquidity support of committed bank credit arrangements. Southern Company and the traditional operating companies may also borrow through various other arrangements with banks and extendible commercial note programs. The amounts of commercial paper outstanding and included in notes payable in the balance sheets at December 31, 2007 and December 31, 2006 were $1.2 billion and $1.8 billion, respectively. The amounts of short-term bank loans included in notes payable in the balance sheets at December 31, 2007 and December 31, 2006 were $113 million and $140 million, respectively. There were no extendible commercial notes outstanding at December 31, 2007 and $30 million outstanding at December 31, 2006.
During 2007, the peak amount outstanding for short-term debt was $2.3 billion, and the average amount outstanding was $1.4 billion. The average annual interest rate on short-term debt was 5.3% for 2007 and 5.2% for 2006.
Financial Instruments
The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. In addition, Southern Power’s exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts generally shift substantially all fuel cost responsibility to the purchaser. Each of the traditional operating companies has implemented fuel-hedging programs at the instruction of their respective state PSCs. Together with Southern Power, the traditional operating companies may enter into hedges of forward electricity sales.
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At December 31, 2007, the fair value gains/(losses) of energy-related derivative contracts was reflected in the financial statements as follows:
The fair value gains or losses for hedges that are recoverable through the regulatory fuel clauses are recorded as regulatory assets and liabilities and are recognized in earnings at the same time the hedged items affect earnings. For other hedges qualifying as cash flow hedges, including those of Southern Power, the fair value gains or losses are recorded in other comprehensive income and are reclassified into earnings at the same time the hedged items affect earnings. For 2007, 2006, and 2005, the pre-tax gains/(losses) reclassified from other comprehensive income to fuel expense or revenues were not material. For the year 2008, approximately $1 million of gains are expected to be reclassified from other comprehensive income to revenues. There was no significant ineffectiveness recorded in earnings for any period presented. Southern Company has energy-related hedges in place up to and including 2010.
During 2006 and 2007, Southern Company entered into derivative transactions to reduce its exposure to a potential phase-out of certain income tax credits related to synthetic fuel production in 2007. In accordance with Section 45K of the Internal Revenue Code, these tax credits are subject to limitation as the annual average price of oil increases. At December 31, 2007, the fair value of all derivative transactions related to synthetic fuel production was a $43 million net asset. For 2007, 2006, and 2005, the fair value gain/(loss) recognized in other income (expense) to mark the transactions to market was $27 million, $(32) million, and $(7) million, respectively.
Southern Company and certain subsidiaries also enter into derivatives to hedge exposure to changes in interest rates. Derivatives related to fixed-rate securities are accounted for as fair value hedges. Derivatives related to variable rate securities or forecasted transactions are accounted for as cash flow hedges. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. As such, no material ineffectiveness has been recorded in earnings for any period presented.
At December 31, 2007, Southern Company had $865 million notional amount of interest rate swaps and options outstanding with net fair value losses of $21 million as follows:
Cash Flow Hedges
*
Hedged using the Securities Industry and Financial Markets Association Municipal Swap Index (SIFMA), (Formerly the Bond Market Association/PSA Municipal Swap Index)
**
Interest rate collar with variable rate based on a percentage of 1-month LIBOR (showing rate cap)
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For fair value hedges where the hedged item is an asset, liability, or firm commitment, the changes in the fair value of the hedging derivatives are recorded in earnings and are offset by the changes in the fair value of the hedged item.
The fair value gain or loss for cash flow hedges is recorded in other comprehensive income and is reclassified into earnings at the same time the hedged items affect earnings. In 2007, 2006, and 2005, the Company incurred net gains/(losses) of $9 million, $1 million, and $(19) million, respectively, upon termination of certain interest derivatives at the same time it issued debt. The effective portion of these gains/(losses) have been deferred in other comprehensive income and will be amortized to interest expense over the life of the original interest derivative. For 2007, 2006, and 2005, approximately $15 million, $1 million, and $10 million, respectively, of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2008, pre-tax losses of approximately $16 million are expected to be reclassified from other comprehensive income to interest expense. The Company has interest-related hedges in place through 2019 and has deferred gains/(losses) that are being amortized through 2037.
7. COMMITMENTS
Construction Program
Southern Company is engaged in continuous construction programs, currently estimated to total $4.5 billion in 2008, $4.8 billion in 2009, and $4.3 billion in 2010. These amounts include $176 million, $188 million, and $170 million in 2008, 2009, and 2010, respectively, for construction expenditures related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included herein under “Fuel and Purchased Power Commitments.” The construction programs are subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include: changes in business conditions; acquisition of additional generating assets; revised load growth estimates; changes in environmental statutes and regulations; changes in existing nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2007, significant purchase commitments were outstanding in connection with the ongoing construction program, which includes new facilities and capital improvements to transmission, distribution, and generation facilities, including those to meet environmental standards.
Long-Term Service Agreements
The traditional operating companies and Southern Power have entered into Long-Term Service Agreements (LTSAs) with General Electric (GE), ABB Power Generation, Inc., and Mitsubishi Power Systems Americas, Inc. for the purpose of securing maintenance support for the combined cycle and combustion turbine generating facilities owned or under construction by the subsidiaries. The LTSAs cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. The LTSAs are also obligated to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract.
In general, these LTSAs are in effect through two major inspection cycles per unit. Scheduled payments under the LTSAs, which are subject to price escalation, are made at various intervals based on actual operating hours or number of gas turbine starts of the respective units. Total remaining payments under these agreements for facilities owned are currently estimated at $2.3 billion over the remaining life of the agreements, which are currently estimated to range up to 40 years. However, the LTSAs contain various cancellation provisions at the option of the purchasers.
Georgia Power has also entered into an LTSA with GE through 2014 for neutron monitoring system parts and electronics at Plant Hatch. Total remaining payments to GE under this agreement are currently estimated at $9 million. The contract contains cancellation provisions at the option of Georgia Power.
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Payments made under the LTSAs prior to the performance of any work are recorded as a prepayment in the balance sheets. All work performed is capitalized or charged to expense (net of any joint owner billings), as appropriate based on the nature of the work.
Limestone Commitments
As part of Southern Company’s program to reduce sulfur dioxide emissions from certain of its coal plants, the traditional operating companies are constructing certain equipment and have entered into various long-term commitments for the procurement of limestone to be used in such equipment. Contracts are structured with tonnage minimums and maximums in order to account for changes in coal burn and sulfur content. Southern Company has a minimum contractual obligation of 7.7 million tons, equating to approximately $305 million, through 2019. Estimated expenditures over the next five years are $7 million in 2008, $13 million in 2009, $36 million in 2010, $34 million in 2011, and $35 million in 2012.
Fuel and Purchased Power Commitments
To supply a portion of the fuel requirements of the generating plants, Southern Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide emission allowances. Natural gas purchase commitments contain fixed volumes with prices based on various indices at the time of delivery. Amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2007. Also, Southern Company has entered into various long-term commitments for the purchase of capacity and electricity. Total estimated minimum long-term obligations at December 31, 2007 were as follows:
Additional commitments for fuel will be required to supply Southern Company’s future needs. Total charges for nuclear fuel included in fuel expense amounted to $144 million in 2007, $137 million in 2006, and $134 million in 2005.
Operating Leases
In 2001, Mississippi Power began the initial 10-year term of a lease agreement for a combined cycle generating facility built at Plant Daniel for approximately $370 million. In 2003, the generating facility was acquired by Juniper Capital L.P. (Juniper), whose partners are unaffiliated with Mississippi Power. Simultaneously, Juniper entered into a restructured lease agreement with Mississippi Power. Juniper has also entered into leases with other parties unrelated to Mississippi Power. The assets leased by Mississippi Power comprise less than 50% of Juniper’s assets. Mississippi Power is not required to consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease. The initial lease term ends in 2011, and the lease includes a purchase and renewal option based on the cost of the facility at the inception of the lease. Mississippi Power is required to amortize approximately 4% of the initial acquisition cost over the initial lease term. Eighteen months prior to the end of the initial lease, Mississippi Power may elect to renew for 10 years. If the lease is renewed, the agreement
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calls for Mississippi Power to amortize an additional 17% of the initial completion cost over the renewal period. Upon termination of the lease, at Mississippi Power’s option, it may either exercise its purchase option or the facility can be sold to a third party.
The lease provides for a residual value guarantee, approximately 73% of the acquisition cost, by Mississippi Power that is due upon termination of the lease in the event that Mississippi Power does not renew the lease or purchase the assets and that the fair market value is less than the unamortized cost of the asset. A liability of approximately $7 million and $9 million for the fair market value of this residual value guarantee is included in the balance sheets as of December 31, 2007 and 2006, respectively.
Southern Company also has other operating lease agreements with various terms and expiration dates. Total operating lease expenses were $163 million, $161 million, and $150 million for 2007, 2006, and 2005, respectively. Southern Company includes any step rents, escalations, and lease concessions in its computation of minimum lease payments, which are recognized on a straight-line basis over the minimum lease term. At December 31, 2007, estimated minimum lease payments for noncancelable operating leases were as follows:
For the traditional operating companies, a majority of the barge and rail car lease expenses are recoverable through fuel cost recovery provisions. In addition to the above rental commitments, Alabama Power and Georgia Power have obligations upon expiration of certain leases with respect to the residual value of the leased property. These leases expire in 2009, 2010, and 2011, and the maximum obligations are $20 million, $62 million, and $41 million, respectively. At the termination of the leases, the lessee may either exercise its purchase option, or the property can be sold to a third party. Alabama Power and Georgia Power expect that the fair market value of the leased property would substantially reduce or eliminate the payments under the residual value obligations.
Guarantees
Prior to the spin-off, Southern Company made separate guarantees to certain counterparties regarding performance of contractual commitments by Mirant’s trading and marketing subsidiaries. Southern Company has paid approximately $1.4 million in connection with the guarantees. The total notional amount of guarantees outstanding at December 31, 2007 is less than $10 million.
As discussed earlier in this Note under “Operating Leases,” Alabama Power, Georgia Power, and Mississippi Power have entered into certain residual value guarantees.
8. COMMON STOCK
Stock Issued
In 2007, Southern Company raised $379 million (11.6 million shares) from the issuance of new common shares and $159 million (5.3 million shares) from the issuance of treasury stock under the Company’s various stock programs.
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In 2006, Southern Company raised $1 million (53,000 shares) from the issuance of new common shares and $136 million (5 million shares) from the issuance of treasury stock under the Company’s various stock programs.
Shares Reserved
At December 31, 2007, a total of 68 million shares were reserved for issuance pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside Directors Stock Plan, and the Omnibus Incentive Compensation Plan (stock option plan).
Stock Option Plan
Southern Company provides non-qualified stock options to a large segment of its employees ranging from line management to executives. As of December 31, 2007, 6,728 current and former employees participated in the stock option plan. The maximum number of shares of common stock that may be issued under this plan may not exceed 40 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. Southern Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. For certain stock option awards, a change in control will provide accelerated vesting.
Southern Company’s activity in the stock option plan for 2007 is summarized below:
The number of stock options vested, and expected to vest in the future, as of December 31, 2007 was not significantly different from the number of stock options outstanding at December 31, 2007 as stated above. As of December 31, 2007, the weighted average remaining contractual term for the options outstanding and options exercisable was 6.5 years and 5.3 years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $272 million and $224 million, respectively.
As of December 31, 2007, there was $10 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 10 months.
The total intrinsic value of options exercised during the years ended December 31, 2007, 2006, and 2005 was $81 million, $36 million, and $130 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $31 million, $14 million, and $50 million, respectively, for the years ended December 31, 2007, 2006, and 2005.
Southern Company has a policy of issuing shares to satisfy share option exercises. Cash received from issuances related to option exercises under the share-based payment arrangements for the years ended December 31, 2007, 2006, and 2005 was $195 million, $77 million, and $213 million, respectively.
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Diluted Earnings Per Share
For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to outstanding options under the stock option plan. The effect of the stock options was determined using the treasury stock method. Shares used to compute diluted earnings per share are as follows:
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2007, consolidated retained earnings included $5.0 billion of undistributed retained earnings of the subsidiaries. Southern Power’s credit facility contains potential limitations on the payment of common stock dividends; as of December 31, 2007, Southern Power was in compliance with all such requirements.
9. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act (Act), Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies’ nuclear power plants. The Act provides funds up to $10.8 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $300 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors. A company could be assessed up to $101 million per incident for each licensed reactor it operates but not more than an aggregate of $15 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power, based on its ownership and buyback interests, is $201 million and $203 million, respectively, per incident, but not more than an aggregate of $30 million per company 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 on or before August 31, 2008.
Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members’ nuclear generating facilities.
Additionally, both companies have policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.3 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.
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. Alabama Power and Georgia Power each purchase the maximum limit allowed by NEIL, subject to ownership limitations. Each facility has elected a 12-week waiting period.
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Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for Alabama Power and Georgia Power under the NEIL policies would be $37 million and $51 million, respectively.
Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.
All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.
10. SEGMENT AND RELATED INFORMATION
Southern Company’s reportable business segments are the sale of electricity in the Southeast by the four traditional operating companies and Southern Power. The “All Other” column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in synthetic fuels and leveraged lease projects, telecommunications, and energy-related services. Southern Power’s revenues from sales to the traditional operating companies were $547 million, $492 million, and $557 million in 2007, 2006, and 2005, respectively. In addition, see Note 1 under “Related Party Transactions” for information regarding revenues from services for synthetic fuel production that are included in the cost of fuel purchased by Alabama Power and Georgia Power. All other intersegment revenues are not material. Financial data for business segments and products and services are as follows:
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Business Segment
Products and Services
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11. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 2007 and 2006 are as follows:
Southern Company’s business is influenced by seasonal weather conditions.
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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
For the Periods Ended December 2003 through 2007
Southern Company and Subsidiary Companies 2007 Annual Report
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For the Periods Ended December 2003 through 2007
Southern Company and Subsidiary Companies 2007 Annual Report
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ALABAMA POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Alabama Power Company 2007 Annual Report
The management of Alabama Power Company (the “Company”) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Under management’s supervision, an evaluation of the design and effectiveness of the Company’s internal control over financial reporting was conducted based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2007.
This Annual Report does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report.
/s/ Charles D. McCrary
Charles D. McCrary
President and Chief Executive Officer
/s/ Art P. Beattie
Art P. Beattie
Executive Vice President, Chief Financial Officer, and Treasurer
February 25, 2008
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Alabama Power Company
We have audited the accompanying balance sheets and statements of capitalization of Alabama Power Company (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2007 and 2006, 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, 2007. 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 II-123 to II-158) present fairly, in all material respects, the financial position of Alabama Power Company at December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the financial statements, in 2006 the Company changed its method of accounting for the funded status of defined benefit pension and other postretirement plans.
/s/ Deloitte & Touche LLP
Birmingham, Alabama
February 25, 2008
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Alabama Power Company 2007 Annual Report
OVERVIEW
Business Activities
Alabama Power Company (the Company) operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of the Company’s primary business of selling electricity. These factors include the ability to maintain a stable regulatory environment, to achieve energy sales growth, and to effectively manage and secure timely recovery of rising costs. These costs include those related to growing demand, increasingly stringent environmental standards, fuel prices, capital expenditures, and restoration following major storms. Appropriately balancing these required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future.
Since 2005, the Company has completed a number of successful regulatory proceedings that provide for the timely recovery of costs. These regulatory actions are expected to assist the Company’s continued focus on providing reliable electrical service to customers while maintaining a stable financial position.
Key Performance Indicators
In striving to maximize shareholder value while providing cost-effective energy to customers, the Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. The Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company’s results.
Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. The fossil/hydro 2007 Peak Season EFOR of 0.59% was better than the target. The nuclear generating fleet also uses Peak Season EFOR as an indicator of availability and efficient generation fleet operations during the peak season. The nuclear 2007 Peak Season EFOR of 0.20% was also 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, expected weather conditions, and expected capital expenditures. The performance for 2007 was better than target for these reliability measures.
Net income after dividends on preferred and preference stock is the primary component of the Company’s contribution to Southern Company’s earnings per share goal. The Company’s 2007 results compared with its targets for some of these key indicators are reflected in the following chart.
See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The financial performance achieved in 2007 reflects the continued management emphasis, as well as the commitment shown by employees in achieving or exceeding these key performance expectations.
Earnings
The Company’s financial performance remained strong in 2007 despite the challenges of rising costs. The Company’s net income after dividends on preferred and preference stock of $580 million in 2007 increased $62 million (11.9%) over the prior year. This improvement was primarily due to an increase in retail base rate revenues resulting from an increase in rates under Rate Stabilization
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Alabama Power Company 2007 Annual Report
and Equalization Plan (Rate RSE) and Rate Certificated New Plant (Rate CNP) for environmental costs that took effect January 1, 2007 as well as favorable weather conditions, partially offset by higher non-fuel operating expenses and increased interest expense.
The Company’s 2006 net income after dividends on preferred and preference stock was $518 million, representing a $10 million (1.9%) increase from the prior year. This improvement was primarily due to retail and wholesale revenue growth offset by higher non-fuel operating expenses and increased interest expense.
The Company’s 2005 net income after dividends on preferred stock was $508 million, representing a $27 million (5.6%) increase from the prior year. This improvement was primarily due to retail and wholesale revenue growth and increases in transmission revenues, partially offset by higher non-fuel operating expenses.
RESULTS OF OPERATIONS
A condensed income statement follows:
Operating Revenues
Operating revenues for 2007 were $5.4 billion, reflecting a $345 million increase from 2006. The following table summarizes the principal factors that have affected operating revenues for the past three years:
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Alabama Power Company 2007 Annual Report
Retail revenues in 2007 were $4.4 billion. These revenues increased $411 million (10.3%) in 2007, $374 million (10.3%) in 2006, and $329 million (10.0%) in 2005. These increases were primarily due to increased fuel revenue and base rate increases of 5.3% in January 2007, 2.6% in January 2006, and 1.0% in January 2005. See FUTURE EARNINGS POTENTIAL - “PSC Matters” herein and Note 3 to the financial statements under “Retail Regulatory Matters” for additional information.
Fuel rates billed to customers are designed to fully recover fluctuating fuel and purchased power costs over a period of time. Fuel revenues generally have no effect on net income because they represent the recording of revenues to offset fuel and purchased power expenses. See FUTURE EARNINGS POTENTIAL - “PSC Matters - Retail Fuel Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters - Fuel Cost Recovery” for additional information.
Wholesale revenues from sales to non-affiliated utilities were as follows:
Wholesale revenues to non-affiliates include unit power sales under long-term contracts to Florida utilities and sales to wholesale customers within the Company’s service territory. Capacity revenues under unit power sales contracts reflect the recovery of fixed costs and a return on investment, and under these contracts, energy is generally sold at variable cost. Fluctuations in oil and natural gas prices, which are the primary fuel sources for unit power sales customers, influence changes in these energy sales. However, because energy is generally sold at variable cost, these fluctuations have a minimal effect on earnings. No significant declines in the amount of capacity revenues are scheduled until the termination of the unit power sales contracts in May 2010. Short-term opportunity energy sales are also included in wholesale energy sales to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above the Company’s variable cost to produce the energy.
Wholesale revenues from sales to affiliated companies within the Southern Company system will vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliated sales and purchases are made in accordance with the Intercompany Interchange Contract (IIC) as approved by the Federal Energy Regulatory Commission (FERC). In 2007, wholesale revenues from sales to affiliates decreased $71.9 million primarily due to a 37.0% decrease in kilowatt-hour (KWH) sales to affiliates as a result of a decrease in the availability of the Company’s generating resources because of an increase in customer demand within the Company’s service territory. In 2006, wholesale revenues decreased $73.0 million primarily due to a 16.7% decrease in price and a 10.3% decrease in KWH sales to affiliates as a result of a decrease in the availability of the Company’s generating resources because of an increase in customer demand within the Company’s service territory. In 2005, wholesale revenues decreased $19.4 million primarily due to a 20.7% decrease in KWH sales to affiliates as a result of a decrease in the availability of the Company’s generating resources due to an increase in customer demand within the Company’s service territory. Excluding the capacity revenues, these transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through the Company’s energy cost recovery clause (Rate ECR).
Other operating revenues in 2007 increased $13.5 million (8.0%) from 2006 primarily due to a $4.0 million increase in revenues from electric property associated with pole attachment and building rentals, a $2.6 million increase in transmission revenues, and a $2.5 million increase in revenues from gas-fueled co-generation steam facilities. In 2006, other operating revenues decreased $17.6 million (9.5%) from 2005 primarily due to a decrease of $14.6 million in revenues from gas-fueled co-generation steam facilities mainly as a result of lower gas prices. In 2005, other operating revenues increased $35.0 million (23.2%) from 2004 due to an increase of $20 million in revenues from gas-fueled co-generation steam facilities primarily as a result of higher gas prices, a $7.7 million increase in transmission revenues, and a $3.9 million increase from rent from affiliated companies primarily related to leased
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transmission facilities. Since co-generation steam revenues are generally offset by fuel expense, these revenues did not have a significant impact on earnings for any year reported.
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2007 and the percent change by year were as follows:
Retail energy sales in 2007 were 0.5% higher than in 2006. Energy sales in the residential and commercial sectors led the growth with a 1.3% and a 2.8% increase, respectively, due primarily to weather-driven increased demand. Industrial sales decreased 1.6% during the year primarily as a result of decreased sales demand in textiles and food, primary metals, and chemical sectors.
Retail energy sales in 2006 were 1.2% higher than in 2005. Energy sales in the residential and commercial sectors led the growth with a 3.1% and a 2.1% increase, respectively, due primarily to weather-driven increased demand. Industrial sales decreased 0.7% as several large textile facilities discontinued or substantially reduced their operations in 2006. In addition, industrial sales decreased due to pulp and paper customers utilizing self-generation as a result of lower gas prices during the year compared to 2005.
Retail energy sales in 2005 were 2.7% higher than 2004 despite interruptions during Hurricanes Dennis and Katrina. Energy sales in the residential sector led the growth with a 4.1% increase in 2005 due primarily to increased demand. Commercial sales increased 1.7% in 2005 primarily due to continued customer growth. Industrial sales increased 2.2% during the year with chemical, primary metals, and automotive leading the growth in industrial energy consumption. In addition, the paper sector chose to purchase rather than self-generate which contributed to increased sales.
Fuel and Purchased Power Expenses
Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market. Details of the Company’s electricity generated and purchased were as follows:
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Fuel and purchased power expenses were $2.2 billion in 2007, an increase of $101.9 million (4.9%) above the prior year costs. This increase was the result of a $70.3 million increase in the cost of fuel and a $31.6 million increase related to the volume of KWHs generated and purchased.
Fuel and purchased power expenses were $2.1 billion in 2006, an increase of $184.1 million (9.6%) above the prior year costs. This increase was the result of a $128.7 million increase in the cost of fuel and a $55.4 million increase related to the volume of KWHs generated and purchased.
Fuel and purchased power expenses were $1.9 billion in 2005, an increase of $315.4 million (19.7%) above the prior year costs. This increase was the result of a $367.4 million increase in the cost of fuel offset by a $52.0 million decrease related to the volume of KWHs generated and purchased.
Purchased power consists of purchases from affiliates in the Southern Company system and non-affiliated companies. Purchased power transactions among the Company, its affiliates, and non-affiliates will vary from period to period depending on demand and the availability and variable production cost of generating resources at each company. Purchased power from non-affiliates decreased $27.1 million (21.8%) in 2007 due to a 22.6% decrease in the amount of energy purchased. In 2006, purchased power from non-affiliates decreased $64.7 million (34.3%) due to a 26.8% decrease in the amount of energy purchased and a 10.3% decrease in purchased power prices over the previous year. In 2005, purchased power from non-affiliates increased $2.5 million (1.0%) due to a 14.3% increase in purchased power prices over the previous year.
While there has been a significant upward trend in the cost of coal and natural gas since 2003, prices moderated somewhat in 2006 and 2007. Coal prices have been influenced by a worldwide increase in demand from developing countries, as well as increases in mining and fuel transportation costs. While demand for natural gas in the United States continued to increase in 2007, natural gas supplies have also risen due to increased production and higher storage levels. During 2007, uranium prices were volatile and increased over the course of the year due to increasing long-term demand with primary production levels at approximately 55% to 60% of demand. Secondary supplies and inventories were sufficient to fill the primary production shortfall.
Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s Rate ECR. The Company, along with the Alabama Public Service Commission (PSC), continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See FUTURE EARNINGS POTENTIAL - “PSC Matters - Retail Fuel Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters - Fuel Cost Recovery” for additional information.
Other Operations and Maintenance Expenses
In 2007, other operations and maintenance expenses increased $89.3 million (8.1%) primarily due to a $28.5 million increase in steam production expense related to environmental mandates and scheduled outage costs, a $19.6 million increase in transmission and distribution expense related to overhead line clearing costs, a $19.0 million increase in administrative and general expenses related to an increase in the expenses for the injuries and damages reserve, outside services, and employee benefits, an $8.1 million increase in nuclear production expense related to scheduled outage cost, a $4.7 million increase in customer accounts expense associated with customer service expenses, and a $9.4 million increase in miscellaneous other operations and maintenance expenses. In 2006, other operations and maintenance expenses increased $52.8 million (5.1%) primarily due to an $18.8 million increase in administrative and general expenses related to employee benefits, a $10.1 million increase in nuclear production expense related to both routine operation and scheduled outage costs, a $9.8 million increase in transmission and distribution expense related to overhead and underground line costs, a $5.4 million increase in steam production expense related to environmental costs, and a $8.7 million increase in miscellaneous other operations and maintenance expenses. In 2005, other operations and maintenance expenses increased $96.7 million (10.2%). This increase was primarily due to an increase in transmission and distribution expense of $37.3 million as a result of the Alabama PSC accounting order to offset the costs of the damage from Hurricane Ivan in September 2004 and to restore a balance in the natural disaster reserve. See Notes 1 and 3 to the financial statements under “Natural Disaster Reserve” and “Natural Disaster Cost Recovery,” respectively, for additional information. In addition, steam production expense increased $28.1 million related to scheduled outage costs, administrative and general expenses increased $20.7 million related to employee benefits, and miscellaneous other operations and maintenance expenses increased $10.6 million.
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Alabama Power Company 2007 Annual Report
Depreciation and Amortization
Depreciation and amortization expenses increased $20.5 million (4.5%) in 2007 primarily due to additions to property, plant, and equipment related to environmental mandates and distribution projects. In 2006, depreciation and amortization expenses increased $24.5 million (5.7%) primarily due to additions to property, plant, and equipment related to environmental and distribution projects. In 2005, depreciation and amortization expenses remained relatively flat compared to the prior year, increasing only $0.6 million (0.1%). During 2005, the depreciation rates used by the Company were adjusted based on a periodic external study that is used to determine the appropriateness of the rates utilized. Also in 2005, additions to property, plant, and equipment, which resulted in increased depreciation expense, were offset by the suspension of $18 million in nuclear decommissioning costs by the Alabama PSC due to the extension of the operating license for both units at Plant Farley. See FUTURE EARNINGS POTENTIAL - “Nuclear Relicensing” and Note 1 to the financial statements under “Nuclear Decommissioning” for additional information.
Taxes Other than Income Taxes
Taxes other than income taxes increased $28.4 million (11.0%) in 2007, $9.3 million (3.7%) in 2006, and $6.0 million (2.5%) in 2005, primarily due to increases in state and municipal public utility license taxes which are directly related to the increase in retail revenues.
Allowance for Equity Funds Used During Construction
Allowance for equity funds used during construction (AFUDC) increased $17.2 million (94.1%) in 2007 primarily due to increases in the amount of construction work in progress related to environmental mandates at generating facilities and transmission and distribution projects compared to the prior year. AFUDC decreased $2.0 million (10.0%) in 2006 primarily due to the timing of construction expenditures compared to the prior year. AFUDC increased $4.1 million (25.6%) in 2005 primarily due to increases in the amount of construction work in progress over the prior year. See Note 1 to the financial statements under “Allowance for Funds Used During Construction (AFUDC)” for additional information.
Interest Expense, Net of Amounts Capitalized
Interest expense, net of amounts capitalized increased $21.5 million (8.5%) in 2007 primarily due to higher interest rates on new issuance of long-term debt and higher interest rates on the Company’s outstanding variable rate securities. Interest expense, net of amounts capitalized, increased $38.7 million (18.1%) in 2006 primarily due to higher interest rates and an increase in the average debt outstanding during the year. Interest expense, net of amounts capitalized increased $3.8 million (2.0%) in 2005 due to an increase in average debt outstanding during the year.
Effects of Inflation
The Company is subject to rate regulation that is based on the recovery of costs. Retail rates may be adjusted annually based on annual projected costs, including estimates for inflation. When historical costs are included, or when inflation exceeds the projected costs used in rate regulation or market-based prices, the effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. In addition, the income tax laws are based on historical costs. Any adverse effect of inflation on the Company’s results of operations has not been substantial. See Note 3 to financial statements under “Retail Regulatory Matters - Rate RSE” for additional information.
FUTURE EARNINGS POTENTIAL
General
The Company operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service area located in the State of Alabama in addition to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the Alabama PSC under cost-based regulatory principles. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES - “Application of Critical Accounting Policies and Estimates - Electric Utility Regulation” herein and Note 3 to the financial statements under “FERC Matters” and “Retail Regulatory Matters” for additional information about regulatory matters.
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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 stable regulatory environment that continues to allow for the recovery of all prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the Company’s service area.
Assuming normal weather, sales to retail customers are projected to grow approximately 1.9% annually on average during 2008 through 2012.
Environmental Matters
Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. Some of the factors driving the potential for such an increase are higher commodity costs, market demand for labor, and scope additions and clarifications. The timing, specific requirements, and estimated costs could also change as environmental statutes and regulations are adopted or modified. See Note 3 to the financial statements under “Environmental Matters” for additional information.
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including the Company, alleging that it had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against the Company in the U.S. District Court for the Northern District of Alabama after the Company was dismissed from the original action. In these lawsuits, the EPA alleged that NSR violations occurred at five coal-fired generating facilities operated by the Company. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units.
In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between the Company and the EPA, resolving the alleged NSR violations at Plant Miller. The consent decree required the Company to pay $100,000 to resolve the government’s claim for a civil penalty and to donate $4.9 million of sulfur dioxide emission allowances to a nonprofit charitable organization and formalized specific emissions reductions to be accomplished by the Company, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in Alabama granted the Company’s motion for summary judgment and entered final judgment in favor of the Company on the EPA’s claims related to all of the remaining plants: Plants Barry, Gaston, Gorgas, and Greene County.
The plaintiffs appealed the district court’s decision to the U.S. Court of Appeals for the Eleventh Circuit, and the appeal was stayed by the Appeals Court pending the U.S. Supreme Court’s decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke Energy case in April 2007. On October 5, 2007, the U.S. District Court for the Northern District of Alabama issued an order in the Company’s case indicating a willingness to re-evaluate its previous decision in light of the Supreme Court’s Duke Energy opinion. On December 21, 2007, the Eleventh Circuit vacated the district court’s decision in the Company’s case and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court’s decision in the Duke Energy case. The final outcome of these matters cannot be determined at this time.
The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in this matter could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
The EPA has issued a series of proposed and final revisions to its NSR regulations under the Clean Air Act, many of which have been subject to legal challenges by environmental groups and states. In June 2005, the U.S. Court of Appeals for the District of Columbia
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Circuit upheld, in part, the EPA’s revisions to NSR regulations that were issued in December 2002 but vacated portions of those revisions addressing the exclusion of certain pollution control projects. These regulatory revisions have been adopted by the State of Alabama. In March 2006, the U.S. Court of Appeals for the District of Columbia Circuit also vacated an EPA rule which sought to clarify the scope of the existing routine maintenance, repair and replacement exclusion. The EPA has also published proposed rules clarifying the test for determining when an emissions increase subject to the NSR permitting requirements has occurred. The impact of these proposed rules will depend on adoption of the final rules by the EPA and the State of Alabama’s implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.
Carbon Dioxide Litigation
In July 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005, and no decision has been issued. The ultimate outcome of these matters cannot be determined at this time.
Environmental Statutes and Regulations
General
The Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; and the Endangered Species Act. Compliance with these environmental requirements involves significant capital and operating costs, which are expected to be recovered through existing ratemaking provisions. Through 2007, the Company had invested approximately $1.7 billion in capital projects to comply with these requirements, with annual totals of $469 million, $260 million, and $256 million for 2007, 2006, and 2005, respectively. The Company expects that capital expenditures to assure compliance with existing and new statutes and regulations will be an additional $646 million, $617 million, and $126 million for 2008, 2009, and 2010, respectively. The Company’s compliance strategy is impacted by changes to existing environmental laws, statutes, and regulations, the cost, availability, and existing inventory of emission allowances, and the Company’s fuel mix. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY - “Capital Requirements and Contractual Obligations” herein.
Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company. New environmental legislation or regulations, or changes to existing statutes or regulations, could affect many areas of the Company’s operations; however, the full impact of any such changes cannot be determined at this time.
Air Quality
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2007, the Company had spent approximately $1.4 billion in reducing sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been announced and are currently being installed at several plants to further reduce SO2, NOx, and mercury emissions, maintain compliance with existing regulations, and meet new requirements.
In 2004, the EPA designated nonattainment areas under an eight-hour ozone standard. Areas within the Company’s service area that were designated as nonattainment under the eight-hour ozone standard included Jefferson and Shelby Counties, near and including
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Birmingham. The Birmingham area was redesignated to attainment by the EPA in June 2006, and the EPA subsequently approved a maintenance plan for the area to address future exceedances of the standard. In December 2006, the U.S. Court of Appeals for the District of Columbia Circuit vacated the first set of implementation rules adopted in 2004 and remanded the rules to the EPA for further refinement. On June 20, 2007, the EPA proposed additional revisions to the current eight-hour ozone standard which, if enacted, could result in designation of new nonattainment areas within the Company’s service territory. The EPA has requested comment and is expected to publish final revisions to the standard in 2008. The impact of this decision, if any, cannot be determined at this time and will depend on subsequent legal action and/or future nonattainment designations and state regulatory plans.
During 2005, the EPA’s fine particulate matter nonattainment designations became effective for several areas within the Company’s service area. State plans for addressing the nonattainment designations under the existing standard are required by April 2008 and could require further reductions in SO2 and NOx emissions from power plants. In September 2006, the EPA published a final rule which increased the stringency of the 24-hour average fine particulate matter air quality standard. In December 2007, state agencies recommended to the EPA that Jefferson County (Birmingham) and Etowah County (Gadsden) in Alabama be designated as nonattainment for this standard. The EPA plans to designate nonattainment areas based on the new standard by December 2009. The ultimate outcome of this matter depends on the development and submittal of the required state plans and resolution of pending legal challenges and, therefore, cannot be determined at this time.
The EPA issued the final Clean Air Interstate Rule in March 2005. This cap-and-trade rule addresses power plant SO2 and NOx emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including the State of Alabama, are subject to the requirements of the rule. The rule calls for additional reductions of NOx and/or SO2 to be achieved in two phases, 2009/2010 and 2015. The State of Alabama has an EPA-approved implementation plan for this rule. These reductions will be accomplished by the installation of additional emission controls at the Company’s coal-fired facilities and/or by the purchase of emission allowances from a cap-and-trade program.
The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized in July 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves (1) the application of Best Available Retrofit Technology (BART) to certain sources built between 1962 and 1977 and (2) the application of any additional emissions reductions which may be deemed necessary for each designated area to achieve reasonable progress by 2018 toward the natural conditions goal. Thereafter, for each 10-year planning period, additional emissions reductions will be required to continue to demonstrate reasonable progress in each area during that period. For power plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for SO2 and NOx. Extensive studies were performed for each of the Company’s affected units to demonstrate that additional particulate matter controls are not necessary under BART. States are currently completing implementation plans that contain strategies for BART and any other measures required to achieve the first phase of reasonable progress.
The impacts of the eight-hour ozone and the fine particulate matter nonattainment designations, and the Clean Air Visibility Rule on the Company will depend on the development and implementation of rules at the state level. Therefore, the full effects of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO2 and NOx emission controls within the next several years to assure continued compliance with applicable air quality requirements.
In March 2005, the EPA published the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emission allowance trading market. The final Clean Air Mercury Rule was challenged in the U.S. Court of Appeals for the District of Columbia Circuit. The petitioners alleged that the EPA was not authorized to establish a cap-and-trade program for mercury emissions and instead the EPA must establish maximum achievable control technology standards for coal-fired electric utility steam generating units. On February 8, 2008, the court vacated the Clean Air Mercury Rule. The Company’s overall environmental compliance strategy relies primarily on a combination of SO2 and NOx controls to reduce mercury emissions. Any significant changes in the strategy will depend on the outcome of any appeals and/or future federal and state rulemakings. Future rulemakings could require emission reductions more stringent than required by the Clean Air Mercury Rule.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2007 Annual Report
Water Quality
In July 2004, the EPA published its final technology-based regulations under the Clean Water Act for the purpose of reducing impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures. The rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants. On January 25, 2007, the U.S. Court of Appeals for the Second Circuit overturned and remanded several provisions of the rule to the EPA for revisions. Among other things, the court rejected the EPA’s use of “cost-benefit” analysis and suggested some ways to incorporate cost considerations. The full impact of these regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by State of Alabama regulatory agencies and, therefore, cannot be determined at this time.
Environmental Remediation
The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and release of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation.
Global Climate Issues
Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions continue to be considered in Congress. The ultimate outcome of these proposals cannot be determined at this time; however, mandatory restrictions on the Company’s greenhouse gas emissions could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. The EPA is currently developing its response to this decision. Regulatory decisions that could follow from this response may have implications for both new and existing stationary sources, such as power plants. The ultimate outcome of these rulemaking activities cannot be determined at this time; however, as with the current legislative proposals, mandatory restrictions on the Company’s greenhouse gas emissions could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
In addition, some states are considering or have undertaken actions to regulate and reduce greenhouse gas emissions. For example, on July 13, 2007, the Governor of the State of Florida signed three executive orders addressing reduction of greenhouse gas emissions within the state, including statewide emission reduction targets beginning in 2017. Included in the orders is a directive to the Florida Secretary of Environmental Protection to develop rules adopting maximum allowable emissions levels of greenhouse gases for electric utilities, consistent with the statewide emission reduction targets, and a request to the Florida PSC to initiate rulemaking requiring utilities to produce at least 20% of their electricity from renewable sources. The impact of any similar state requirements on the Company will depend on the future development, adoption, and implementation of state laws or rules governing greenhouse gas emissions, and the ultimate outcome cannot be determined at this time.
International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. Current efforts focus on a potential successor to the Kyoto Protocol for the post 2008 through 2012 timeframe. The outcome and impact of the international negotiations cannot be determined at this time.
The Company continues to evaluate its future energy and emission profiles and is participating in voluntary programs to reduce greenhouse gas emissions and to help develop and advance technology to reduce emissions.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2007 Annual Report
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.
In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales by the Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level.
In late June and July 2007, hearings were held in this proceeding and the presiding administrative law judge issued an initial decision on November 9, 2007 regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the Company to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates, and could also result in refunds of up to $3.9 million, plus interest. The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter.
On June 21, 2007, the FERC issued its final rule regarding market-based rate authority. The FERC generally retained its current market-based rate standards. The impact of this order and its effect on the generation dominance proceeding cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies (including the Company), Southern Power, and Southern Company Services, Inc., as agent, under the terms of which the power pool of Southern Company is operated, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct.
In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms and Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. Southern Company filed with the FERC in November 2006 a compliance plan in connection with the order. On April 19, 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan is not expected to have a material impact on the Company’s financial statements. On November 19, 2007, Southern Company notified the FERC that the plan had been implemented and the FERC division of audits subsequently began an audit pertaining to compliance implementation and related matters, which is ongoing.
Generation Interconnection Agreements
In November 2004, generator company subsidiaries of Tenaska, Inc. (Tenaska), as counterparties to two previously executed interconnection agreements with the Company, filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $11 million previously paid for interconnection facilities. No other similar complaints are pending with the FERC.
On January 19, 2007, the FERC issued an order granting Tenaska’s requested relief. Although the FERC’s order required the modification of Tenaska’s interconnection agreements, under the provisions of the order, the Company determined that no refund was payable to Tenaska. Southern Company requested rehearing asserting that the FERC retroactively applied a new principle to existing interconnection agreements. Tenaska requested rehearing of FERC’s methodology for determining the amount of refunds. The requested rehearings were denied and Southern Company and Tenaska have appealed the orders to the U.S. Circuit Court for the District of Columbia. The final outcome of this matter cannot now be determined.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2007 Annual Report
Hydro Relicensing
In July 2005, the Company filed two applications with the FERC for new 50-year licenses for the Company’s seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin) and for the Lewis Smith and Bankhead developments on the Warrior River. The FERC licenses for all of these nine projects expired in July and August of 2007. Since the FERC did not act on the Company’s new license applications prior to the expiration of the existing licenses, the FERC is required by law to issue annual licenses to the Company, under the terms and conditions of the existing license, until action is taken on the new license applications. The FERC issued an annual license for the Coosa developments on August 8, 2007 and issued an annual license for the Warrior developments on September 6, 2007. These annual licenses are required to be renewed each year by the FERC to allow the Company to continue operation of the projects under the terms of the previous license while the FERC completes review of the applications for new licenses.
In 2006, the Company initiated the process of developing an application to relicense the Martin hydroelectric project located on the Tallapoosa River. The current Martin license will expire in 2013 and the application for a new license is expected to be filed with the FERC in 2011.
Upon or after the expiration of each license, the U.S. Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee. The FERC may grant relicenses subject to certain requirements that could result in additional costs to the Company.
The timing and final outcome of the Company’s relicense applications cannot now be determined.
PSC Matters
Retail Rate Adjustments
In October 2005, the Alabama PSC approved a revision to Rate RSE requested by the Company. Effective January 2007 and thereafter, Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4% per year and any annual adjustment is limited to 5%. Retail rates remain unchanged when the return on retail common equity is projected to be between 13.0% and 14.5%. If the Company’s actual retail return on common equity is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return on common equity fall below the allowed equity return range. On November 30, 2007, the Company made its submission of projected data for calendar year 2008. The Rate RSE increase for 2008 is 3.24%, or $147 million annually, and was effective in January 2008. Under terms of Rate RSE, the maximum increase for 2009 cannot exceed 4.76%. See Note 3 to the financial statements under “Retail Regulatory Matters - Rate RSE” for further information.
The Company’s retail rates, approved by the Alabama PSC, also provide for adjustments to recognize the placing of new generating facilities into retail service and the recovery of retail costs associated with certificated power purchase agreements (PPAs) under Rate CNP. In April 2005, an annual adjustment to Rate CNP, associated with PPAs, decreased retail rates by approximately 0.5%, or $19 million annually. The annual PPA true-up adjustment effective in April 2006 increased retail rates by 0.5%, or $19 million annually. There was no rate adjustment associated with the annual PPA true-up adjustment in April 2007 and there will be no adjustment to the current Rate CNP to recover certificated PPA costs in April 2008. See Note 3 to the financial statements under “Retail Regulatory Matters - Rate CNP” for additional information.
Rate CNP also allows for the recovery of the Company’s retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism, based on forward-looking information, began operation in January 2005 and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on invested capital. Retail rates increased due to environmental costs approximately 1.0% in January 2005, 1.2% in January 2006, 0.6% in January 2007, and 2.4% in January 2008. It is currently anticipated that retail rates will increase approximately 0.6% in 2009 under this provision.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2007 Annual Report
Retail Fuel Cost Recovery
The Company has established fuel cost recovery rates approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. The Company, along with the Alabama PSC, will continue to monitor the under recovered fuel cost balance to determine whether an additional adjustment to billing rates is required.
In June 2007, the Alabama PSC ordered the Company to increase its Rate ECR factor to 3.100 cents per KWH effective with billings beginning July 2007 for the 30-month period ending December 2009. The previous rate of 2.400 cents per KWH had been in effect since January 2006. This increase was intended to permit recovery of energy costs based on an estimate of future energy cost, as well as the collection of the existing under recovered energy cost by the end of 2009. During the 30-month period, the Company will be allowed to include a carrying charge associated with the under recovered fuel costs in the fuel expense calculation. In the event the application of this increased Rate ECR factor results in an over recovered position during this period, the Company will pay interest on any such over recovered balance at the same rate used to derive the carrying cost.
The Company’s under recovered fuel costs as of December 31, 2007 totaled $279.8 million as compared to $301.0 million at December 31, 2006. As a result of the Alabama PSC order, the Company classified $81.7 million and $301.0 million of the under recovered regulatory clause revenues as deferred charges and other assets in the balance sheets as of December 31, 2007 and December 31, 2006, respectively. This classification is based on an estimate which includes such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of the recovery of the under recovered fuel costs. See Note 3 to the financial statements under “Retail Regulatory Matters - Fuel Cost Recovery” for additional information.
Rate ECR revenues, as recorded on the financial statements, are adjusted for the difference in actual recoverable costs and amounts billed in current regulated rates. Accordingly, this approved increase in the billing factor will have no significant effect on the Company’s revenues or net income, but will increase annual cash flow.
Natural Disaster Cost Recovery
The Company maintains a reserve for operations and maintenance expense to cover the cost of damages from major storms to its transmission and distribution facilities. In July 2005 and August 2005, Hurricanes Dennis and Katrina, respectively, hit the coast of Alabama and continued north through the state, causing significant damage in parts of the service territory of the Company. Approximately 241,000 and 637,000 of the Company’s 1.4 million customers were without electrical service immediately after Hurricanes Dennis and Katrina, respectively. The Company sustained significant damage to its distribution and transmission facilities during these storms.
In August 2005, the Company received approval from the Alabama PSC to defer the Hurricane Dennis storm-related operations and maintenance costs (approximately $28 million), which resulted in a negative balance in the natural disaster reserve (NDR). In October 2005, the Company also received similar approval from the Alabama PSC to defer the Hurricane Katrina storm-related operations and maintenance costs (approximately $30 million). See Note 1 and Note 3 to the financial statements under “Natural Disaster Reserve” and “Natural Disaster Cost Recovery,” respectively, for additional information on these reserves.
In December 2005, the Alabama PSC approved a request by the Company to replenish the depleted NDR and allow for recovery of future natural disaster costs. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of uninsured storm damage exceed any established reserve balance. The order also approved a separate monthly NDR charge consisting of two components beginning in January 2006. The first component is intended to establish and maintain a target reserve balance of $75 million for future storms and is an on-going part of customer billing. Assuming no additional storms, the Company currently expects that the target reserve balance could be achieved within four years. The second component of the NDR charge is intended to allow recovery of any existing deferred hurricane related operations and maintenance costs and any future reserve deficits over a 24-month period. Absent further Alabama PSC approval, the maximum total NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account.
At December 31, 2007, the Company had accumulated a balance of $26.1 million in the target reserve for future storms, which is included in the balance sheets under “Other Regulatory Liabilities.” In June 2007, the Company fully recovered its prior storm cost of $51.3 million resulting from Hurricanes Dennis and Katrina. As a result, customer rates decreased by this portion of the NDR charge effective in July 2007.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2007 Annual Report
As revenue from the NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, this increase in revenue and expense will not have an impact on net income but will increase annual cash flow.
Income Tax Matters
Bonus Depreciation
On February 13, 2008, President Bush signed the Economic Stimulus Act of 2008 (Stimulus Act) into law. The Stimulus Act includes a provision that allows 50% bonus depreciation for certain property acquired in 2008 and placed in service in 2008 or, in certain limited cases, 2009. The Company is currently assessing the financial implications of the Stimulus Act; however, the ultimate impact cannot be determined at this time.
Internal Revenue Code Section 199 Domestic Production Deduction
The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in the Internal Revenue Code Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for years 2007 through 2009, and a 9% rate applicable for all years after 2009. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.
Other Matters
In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers’ Accounting for Pensions, the Company recorded non-cash pre-tax pension income of approximately $17 million, $13 million, and $21 million in 2007, 2006, and 2005, respectively. Postretirement benefit costs for the Company were $27 million, $28 million, and $28 million in 2007, 2006, and 2005, respectively. Postretirement benefit costs are expected to trend upward. Such amounts are dependent on several factors including trust earnings and changes to the plans. A portion of pension and postretirement benefit costs is capitalized based on construction-related labor charges. Pension and postretirement benefit costs are a component of the regulated rates and generally do not have a long-term effect on net income. For more information regarding pension and postretirement benefits, see Note 2 to the financial statements.
The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements. See Note 3 to the financial statements for information regarding material issues.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed critical accounting policies and estimates described below with the Audit Committee of Southern Company’s Board of Directors.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2007 Annual Report
Electric Utility Regulation
The Company is subject to retail regulation by the Alabama PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies FASB Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), which requires the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of SFAS No. 71 has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on the Company’s financial statements than they would on a non-regulated company.
As reflected in Note 1 to the financial statements under “Regulatory Assets and Liabilities,” significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines and accounting principles generally accepted in the United States. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s results of operations.
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a loss is considered probable and reasonably estimable in accordance with generally accepted accounting principles. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company’s financial statements. These events or conditions include the following:
•
Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances, hazardous and solid wastes, and other environmental matters.
•
Changes in existing income tax regulations or changes in Internal Revenue Service (IRS) or Alabama Department of Revenue interpretations of existing regulations.
•
Identification of additional sites that require environmental remediation or the filing of other complaints in which the Company may be asserted to be a potentially responsible party.
•
Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant.
•
Resolution or progression of existing matters through the legislative process, the court systems, the IRS, the FERC, or the EPA.
Unbilled Revenues
Revenues related to the sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, and power delivery volume and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company’s results of operations.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2007 Annual Report
New Accounting Standards
Income Taxes
On January 1, 2007, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), which requires companies to determine whether it is “more likely than not” that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. It also provides guidance on the recognition, measurement, and classification of income tax uncertainties, along with any related interest and penalties. The provisions of FIN 48 were applied to all tax positions beginning January 1, 2007. The adoption of FIN 48 did not have a material impact on the Company’s financial statements.
Pensions and Other Postretirement Plans
On December 31, 2006, the Company adopted FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS No. 158), which requires recognition of the funded status of its defined benefit postretirement plans in the balance sheets. Additionally, SFAS No. 158 will require the Company to change the measurement date for its defined benefit postretirement plan assets and obligations from September 30 to December 31 beginning with the year ending December 31, 2008. See Note 2 to the financial statements for additional information.
Fair Value Measurement
The FASB issued FASB Statement No. 157, “Fair Value Measurements” (SFAS No. 157) in September 2006. SFAS No. 157 provides guidance on how to measure fair value where it is permitted or required under other accounting pronouncements. SFAS No. 157 also requires additional disclosures about fair value measurements. The Company adopted SFAS No. 157 in its entirety on January 1, 2008, with no material effect on its financial condition or results of operations.
Fair Value Option
In February 2007, the FASB issued FASB Statement No. 159, “Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115” (SFAS No. 159). This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. The Company adopted SFAS No. 159 on January 1, 2008, with no material effect on its financial condition or results of operations.
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company’s financial condition remained stable at December 31, 2007. Net cash flow from operating activities totaled $1,150 million, $956 million, and $908 million for 2007, 2006, and 2005, respectively. The $194 million increase for 2007 in net cash flow from operating activities is primarily due to an increase in price resulting in an increase to net income, an increase in deferred income tax expense, and lower cash outflows for accounts payable due to timing of payments at December 31, 2007. The $48 million increase for 2006 in operating activities primarily related to higher recovery rates for fuel and purchased power partially offset by the timing of payments for operations expenses. Fuel costs are recoverable in future periods. Under recovered fuel cost is included in the balance sheets as under recovered regulatory clause revenue and deferred under recovered regulatory clause revenues. Net cash used for investing activities totaled $1.3 billion primarily due to gross property additions to utility plant of $1.2 billion. Net cash provided from financing activities totaled $162 million, compared to $14 million in 2006. The $148 million increase is primarily due to cash inflows from proceeds of common stock and pollution control bonds, offset by redemptions of long-term debt. See FUTURE EARNINGS POTENTIAL - “Retail Fuel Cost Recovery” and “Natural Disaster Cost Recovery” for additional information.
Significant balance sheet changes for 2007 include an increase of $671 million in gross plant and an increase of $602 million in long-term debt. In 2006, significant balance sheet changes included an increase of $697 million in gross plant and an increase of $279 million in long-term debt, primarily due to an increase in environmental-related equipment.
The Company’s ratio of common equity to total capitalization, including short-term debt, was 42.5% in 2007, 42.1% in 2006, and 42.2% in 2005. See Note 6 to the financial statements for additional information.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2007 Annual Report
The Company has maintained investment grade ratings from the major rating agencies with respect to debt, preferred securities, preferred stock, and preference stock.
Sources of Capital
The Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, unsecured debt, common stock, preferred stock, and preference stock. However, the type and timing of any financings will depend on market conditions, regulatory approval, and other factors.
Security issuances are subject to regulatory approval by the Alabama PSC. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission (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.
The Company’s current liabilities sometimes exceed current assets because of the Company’s debt due within one year and the periodic use of short-term debt as a funding source primarily to meet scheduled maturities of long-term debt as well as cash needs which can fluctuate significantly due to the seasonality of the business.
To meet short-term cash needs and contingencies, the Company has various internal and external sources of liquidity. At the beginning of 2008, the Company had approximately $74 million of cash and cash equivalents and $1.2 billion of unused credit arrangements with banks, as described below. In addition, the Company has substantial cash flow from operating activities and access to the capital markets, including a commercial paper program, to meet liquidity needs.
The Company maintains committed lines of credit in the amount of $1.2 billion, of which $435 million will expire at various times during 2008. $355 million of the credit facilities expiring in 2008 allow for the execution of term loans for an additional one-year period. $800 million of credit facilities expire in 2012. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.
The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other traditional operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other traditional operating company. The obligations of each company under these arrangements are several and there is no cross affiliate credit support.
As of December 31, 2007, the Company had no commercial paper or extendible commercial notes outstanding. As of December 31, 2006, the Company had $120 million of commercial paper outstanding and no extendible commercial notes outstanding.
Financing Activities
During 2007, the Company issued $850 million of senior notes and $200 million of preference stock and incurred obligations related to the issuance of $265.5 million of tax-exempt bonds. In addition, the Company issued a total of 5.725 million shares of its common stock at $40.00 per share and realized proceeds of $229 million. The proceeds of these issuances were used to repay short-term indebtedness, and for other general corporate purposes.
Also during 2007, the Company paid at maturity $668.5 million of senior notes and redeemed $100 million of junior subordinated notes.
Subsequent to December 31, 2007, the Company issued $300 million of long-term senior notes. The proceeds were used to repay short-term indebtedness and for other general corporate purposes. Additionally, the Company redeemed 1,250 shares of its Flexible Money Market Class A Preferred Stock (Series 2003A), Stated Capital $100,000 Per Share ($125 million aggregate value).
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2007 Annual Report
Credit Rating Risk
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- or Baa3. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. These contracts are primarily for coal purchases. At December 31, 2007, the maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $8 million.
The Company is also party to certain agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade for the Company and/or Georgia Power. These agreements are primarily for natural gas and power price risk management activities. At December 31, 2007, the Company’s exposure related to these agreements was approximately $15 million.
Market Price Risk
Due to cost-based rate regulations, the Company has limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. Company policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
To mitigate future exposure to changes in interest rates, the Company enters into forward starting interest rate swaps and other derivatives that have been designated as hedges. The weighted average interest rate on $1.1 billion of long-term variable interest rate exposure that has not been hedged at January 1, 2008 was 4.19%. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $11 million at January 1, 2008. Subsequent to December 31, 2007, the Company entered into additional interest rate swaps hedging approximately $330 million of floating rate pollution control bonds which together with the current interest rate swaps of $246 million began decreasing the Company’s variable rate exposure by $576 million. As a result, the effect of a 100 basis point change in interest rates for all currently unhedged variable rate long-term debt decreased to approximately $5.7 million. For further information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”
Of the Company’s remaining $497 million of variable interest rate exposure, $247 million relates to tax-exempt auction rate pollution control bonds. Recent weakness in the auction markets has resulted in higher interest rates. The Company has sent notice of conversion of all $247 million of these auction rate securities to a fixed rate interest rate determination method and plans to remarket the auction rate securities in a timely manner. None of the securities are insured or backed by letters of credit that would require approval of a guarantor or security provider. It is not expected that the higher rates as a result of the weakness in the auction markets will be material.
To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts for natural gas purchases. The Company has implemented fuel hedging programs at the instruction of the Alabama PSC.
In addition, the Company’s Rate ECR allows the recovery of specific costs associated with the sales of natural gas that become necessary due to operating considerations at the Company’s electric generating facilities. Rate ECR also allows recovery of the cost of financial instruments used for hedging market price risk up to 75% 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.
At December 31, 2007, exposure from these activities was not material to the Company’s financial position, results of operations, or cash flows. The changes in fair value of energy-related derivative contracts and year-end valuations were as follows at December 31:
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2007 Annual Report
(a)
Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
Unrealized gains and losses from mark-to-market adjustments on derivative contracts related to the Company’s fuel hedging programs are recorded as regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are recovered through the Company’s Rate ECR. Gains and losses on derivative contracts that are not designated as hedges are recognized in the statements of income as incurred. At December 31, 2007, the fair value gains/(losses) of energy-related derivative contracts were reflected in the financial statements as follows:
Unrealized pre-tax gains and losses from energy-related derivative contracts recognized in income were not material for any year presented.
The Company is exposed to market price risk in the event of nonperformance by counterparties to the energy-related derivative contracts. The Company’s policy is to enter into agreements with counterparties that have investment grade credit ratings by Moody’s and Standard & Poor’s or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”
Capital Requirements and Contractual Obligations
The construction program of the Company is currently estimated to be $1.6 billion for 2008, $1.6 billion for 2009, and $1.0 billion for 2010. Environmental expenditures included in these estimated amounts are $646 million, $617 million, and $126 million for 2008, 2009, and 2010, respectively. In addition, over the next three years, the Company estimates spending $595 million on Plant Farley (including $432 million for nuclear fuel), $1,110 million on distribution facilities, and $407 million on transmission additions. See Note 7 to the financial statements under “Construction Program” for additional details.
Actual construction costs may vary from these estimates because of changes in such factors as: business conditions; environmental statutes and regulations; nuclear plant regulations; FERC rules and regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. 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.”
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2007 Annual Report
In addition to the funds required for the Company’s construction program, approximately $760 million will be required by the end of 2010 for maturities of long-term debt. The Company plans to continue, when economically feasible, to retire higher cost securities and replace these obligations with lower-cost capital if market conditions permit.
The Company has also established an external trust fund for postretirement benefits as ordered by the Alabama PSC. The cumulative effect of funding these items over a long period will diminish internally funded capital for other purposes and may require the Company to seek capital from other sources. For additional information, see Note 2 to the financial statements under “Postretirement Benefits.”
Other funding requirements related to obligations associated with scheduled maturities of long-term debt and preferred securities, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, and other purchase commitments, are as follows. See Notes 1, 6, and 7 to the financial statements for additional information.
Contractual Obligations
(a)
All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2008, 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)
On October 26, 2007, the Company announced the redemption on January 1, 2008 of 1,250 shares of Flexible Money Market Class A Preferred Stock (Series 2003A), Cumulative, Par Value $1 Per Share (Stated Capital $100,000 Per Share).
(c)
Preferred and preference stock do not mature; therefore, amounts are provided for the next five years only.
(d)
For additional information, see Notes 1 and 6 to the financial statements.
(e)
The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for 2007, 2006, and 2005 were $1.19 billion, $1.10 billion, and $1.04 billion, respectively.
(f)
The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures excluding those amounts related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services. At December 31, 2007, significant purchase commitments were outstanding in connection with the construction program.
(g)
As part of the Company’s program to reduce sulfur dioxide emissions from certain of its coal plants, the Company is constructing certain equipment and has entered into various long-term commitments for the procurement of limestone to be used in such equipment.
(h)
Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2007.
(i)
Long-term service agreements include price escalation based on inflation indices.
(j)
The Company forecasts postretirement trust contributions over a three-year period. No contributions related to the Company’s pension trust are currently expected during this period. See Note 2 to the financial statements for additional information related to the pension and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2007 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company’s 2007 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales growth and retail rates, storm damage cost recovery and repairs, fuel cost recovery, environmental regulations and expenditures, access to sources of capital, projections for postretirement benefit trust contributions, financing activities, completion of construction projects, filings with state and federal regulatory authorities, impacts of adoption of new accounting rules, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
•
the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, or particulate matter and other substances, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
•
current and future litigation, regulatory investigations, proceedings, or inquiries, including FERC matters and the pending EPA civil action against the Company;
•
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
•
variations in demand for electricity, including those relating to weather, the general economy, population and business growth (and declines), and the effects of energy conservation measures;
•
available sources and costs of fuel;
•
effects of inflation;
•
ability to control costs;
•
investment performance of the Company’s employee benefit plans;
•
advances in technology;
•
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and storm restoration cost recovery;
•
internal restructuring or other restructuring options that may be pursued;
•
potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;
•
the ability of counterparties of the Company to make payments as and when due;
•
the ability to obtain new short- and long-term contracts with neighboring utilities;
•
the direct or indirect effect on the Company’s business resulting from terrorist incidents and the threat of terrorist incidents;
•
interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company’s credit ratings;
•
the ability of the Company to obtain additional generating capacity at competitive prices;
•
catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as an avian influenza, or other similar occurrences;
•
the direct or indirect effects on the Company’s business resulting from incidents similar to the August 2003 power outage in the Northeast;
•
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
•
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
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STATEMENTS OF INCOME
For the Years Ended December 31, 2007, 2006, and 2005
Alabama Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2007, 2006, and 2005
Alabama Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2007 and 2006
Alabama Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2007 and 2006
Alabama Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF CAPITALIZATION
At December 31, 2007 and 2006
Alabama Power Company 2007 Annual Report
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STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2007 and 2006
Alabama Power Company 2007 Annual Report
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STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2007, 2006, and 2005
Alabama Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2007, 2006, and 2005
Alabama Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 2007 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Alabama Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies - the Company, Georgia Power, Gulf Power, and Mississippi Power - are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electricity to retail customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast. Southern Power constructs, acquires, and manages generation assets, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications services to the traditional operating companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy-related businesses. The investments in synthetic fuels ended on December 31, 2007. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants, including the Company’s Plant Farley.
The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable interest entities where the Company is not the primary beneficiary.
The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC) and the Alabama Public Service Commission (PSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from those estimates.
Reclassifications
Certain prior years’ data presented in the financial statements have been reclassified to conform with current year presentation. These reclassifications had no effect on total assets, net income, or cash flows.
The balance sheets and the statements of cash flows have been modified to combine “Long-term Debt Payable to Affiliate Trusts” into “Long-term Debt.” Correspondingly, the statements of income were modified to report “Interest expense to affiliate trusts” together with “Interest expense, net of amounts capitalized.”
Affiliate Transactions
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, purchasing, accounting and statistical analysis, finance and treasury, tax, information resources, marketing, auditing, insurance and pension administration, human resources, systems and procedures, and other services with respect to business and operations and power pool transactions. Costs for these services amounted to $299 million, $266 million, and $246 million during 2007, 2006, and 2005, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.
The Company has an agreement with Southern Nuclear under which Southern Nuclear operates the Company’s Plant Farley and provides the following nuclear-related services at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, statistical analysis, employee relations, and other services with respect to business and operations. Costs for these services amounted to $182 million, $162 million, and $157 million during 2007, 2006, and 2005, respectively.
The Company jointly owns Plant Greene County with Mississippi Power. The Company has an agreement with Mississippi Power under which the Company operates Plant Greene County, and Mississippi Power reimburses the Company for its proportionate share of expenses which were $9.8 million in 2007, $8.6 million in 2006, and $8.2 million in 2005. See Note 4 for additional information.
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NOTES (continued)
Alabama Power Company 2007 Annual Report
Southern Company held a 30% ownership interest in Alabama Fuel Products, LLC (AFP), which produces synthetic fuel, until July 2006, when the ownership interest was terminated. Subsequent to the termination of the membership interest in AFP, the Company continued to purchase fuel from AFP in the amount of $462.1 and $244.4 million in 2007 and 2006, respectively. The Company purchases synthetic fuel from AFP for use at several of the Company’s plants. Total fuel purchases through June 2006 and for the year ended 2005 were $202.2 million and $265.7 million, respectively. In addition, the Company had an agreement with an indirect subsidiary of Southern Company that provides services for AFP. Under this agreement, the Company provided certain accounting functions, including processing and paying fuel transportation invoices, and the Company was reimbursed for its expenses. Amounts billed under this agreement totaled approximately $58.1 million, $56.5 million, and $31.5 million in 2007, 2006, and 2005, respectively. The synthetic fuel purchases and related party transactions were terminated as of December 31, 2007.
The Company had an agreement with Southern Power under which the Company operated and maintained Plant Harris at cost. On August 1, 2007, that agreement was terminated and replaced with a service agreement under which the Company provides to Southern Power labor and other specifically requested services. In 2007, 2006, and 2005, the Company billed Southern Power $2.4 million, $2.2 million, and $1.9 million, respectively, under these agreements. Under a power purchase agreement (PPA) with Southern Power, the Company’s purchased power costs from Plant Harris in 2007, 2006, and 2005 totaled $66.3 million, $61.7 million, and $63.6 million, respectively. The Company also provides the fuel, at cost, associated with the PPA and the fuel cost recognized by the Company was $108.1 million in 2007, $77.8 million in 2006, and $81.3 million in 2005. Additionally, the Company recorded $8.3 million of prepaid capacity expenses included in other deferred charges and other assets in the balance sheets at December 31, 2007 and 2006. See Note 3 under “Retail Regulatory Matters” and Note 7 under “Purchased Power Commitments” for additional information.
In 2007, the Company purchased plots of land in Prattville, Alabama and Chilton County, Alabama from Southern Power. The total purchase price was $4.3 million and is recorded in “Property additions” on the statements of cash flows.
The Company had an agreement with SouthernLINC Wireless to provide digital wireless communications services to the Company. Costs for these services amounted to $5.1 million, $4.9 million, and $5.7 million during 2007, 2006, and 2005, respectively.
Also, see Note 4 for information regarding the Company’s ownership in and PPA with Southern Electric Generating Company (SEGCO) and Note 5 for information on certain deferred tax liabilities due to affiliates.
The Company provides incidental services to, and receives such services from, other Southern Company subsidiaries which are generally minor in duration and/or amount. However, with the hurricane damage experienced by Mississippi Power in 2005, assistance provided to aid in storm restoration, including Company labor, contract labor, and materials, caused an increase in these activities. The total amount of storm restoration provided to Mississippi Power in 2005 was $8.0 million. In 2005, the Company received assistance from affiliated companies in the amount of $5.0 million. These activities were billed at cost.
The traditional operating companies, including the Company, and Southern Power jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under “Fuel Commitments” for additional information.
Revenues
Energy and other revenues are recognized as services are provided. Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract periods. Unbilled revenues are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company continuously monitors the under/over recovered balances and files for revised rates as required or when management deems appropriate depending on the rate. See “Retail Regulatory Matters - Fuel Cost Recovery” in Note 3 for additional information.
The Company has a diversified base of customers. No single customer comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than one percent of revenues.
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NOTES (continued)
Alabama Power Company 2007 Annual Report
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
(a)
Asset retirement and removal liabilities are recorded, deferred income tax assets are recovered, and deferred tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.
(b)
Recovered over the remaining life of the original issue which may range up to 50 years.
(c)
Recorded as earned by employees and recovered as paid, generally within one year.
(d)
Recorded and recovered or amortized as approved or accepted by the Alabama PSC.
(e)
Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clauses.
(f)
Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 under “Retirement Benefits.”
In the event that a portion of the Company’s operations is no longer subject to the provisions of SFAS No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates.
Nuclear Fuel Disposal Costs
The Company has a contract with the United States, acting through the U.S. Department of Energy (DOE) that provides for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contract, and the Company is pursuing legal remedies against the government for breach of contract. An on-site dry spent fuel storage facility at Plant Farley is operational and can be expanded to accommodate spent fuel through the expected life of the plant.
On July 9, 2007, the U.S. Court of Federal Claims awarded the Company $17.3 million, representing all of the direct costs of the expansion of spent nuclear fuel storage facilities from 1998 through 2004. On July 24, 2007, the government filed a motion for
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NOTES (continued)
Alabama Power Company 2007 Annual Report
reconsideration, which was denied on November 1, 2007. The government filed an appeal on January 2, 2008. No amounts have been recognized in the financial statements as of December 31, 2007. The final outcome of this matter cannot be determined at this time, but no material impact on net income is expected as any award received is expected to be returned to customers.
Also, the Energy Policy Act of 1992 established a Uranium Enrichment Decontamination and Decommissioning Fund, which has been funded in part by a special assessment on utilities with nuclear plants. This assessment was paid over a 15-year period; the final installment occurred in 2006 and was fully amortized in September 2007. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense.
Fuel Costs
Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emission allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel.
Income and Other Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.
In accordance with FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), the Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information on the effect of adopting FIN 48.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction.
The Company’s property, plant, and equipment consisted of the following at December 31:
The cost of replacements of property - exclusive of minor items of property - is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific Alabama PSC orders. The Company accrues estimated nuclear refueling costs in advance of the unit’s next refueling outage. The refueling cycle is 18 months for each unit. During 2007, the Company accrued $40.3 million and paid $27.6 million for an outage at Plant Farley Unit 1 and $27.1 million for an outage at Plant Farley Unit 2. At December 31, 2007, the reserve balance totaled $(2.0) million and is included in the balance sheet in other regulatory liabilities.
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NOTES (continued)
Alabama Power Company 2007 Annual Report
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.1% in 2007 and 2006 and 2.9% in 2005. Depreciation studies are conducted periodically to update the composite rates and the information is provided to the Alabama PSC. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.
Asset Retirement Obligations and Other Costs of Removal
Asset retirement obligations are computed as the present value of the ultimate costs for an asset’s future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. The Company has received accounting guidance from the Alabama PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations will continue to be reflected in the balance sheets as a regulatory liability.
The liability recognized to retire long-lived assets primarily relates to the Company’s nuclear facility, Plant Farley. The fair value of assets legally restricted for settling retirement obligations related to nuclear facilities as of December 31, 2007 was $543 million. In addition, the Company has retirement obligations related to various landfill sites and underground storage tanks. In connection with the adoption of FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), the Company also recorded additional asset retirement obligations (and assets) of $35 million related to asbestos removal and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized under Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” and FIN 47 and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Alabama PSC, and are reflected in the balance sheets. See “Nuclear Decommissioning” for further information on amounts included in rates.
Details of the asset retirement obligations included in the balance sheets are as follows:
Nuclear Decommissioning
The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The Company has external trust funds to comply with the NRC’s regulations. Use of the funds is restricted to nuclear decommissioning activities and the funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the Alabama PSC, as well as the Internal Revenue Service (IRS). The trust funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are classified as available-for-sale.
The trust funds are included in the balance sheets at fair value, as obtained from quoted market prices for the same or similar investments. As the external trust funds are actively managed by unrelated parties with limited direction from the Company, the Company does not have the ability to choose to hold securities with unrealized losses until recovery. Through 2005, the Company considered other-than-temporary impairments to be immaterial. However, since the January 1, 2006 effective date of FASB Staff
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NOTES (continued)
Alabama Power Company 2007 Annual Report
Position FAS 115-1/124-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (FSP No. 115-1), the Company considers all unrealized losses to represent other-than-temporary impairments. The adoption of FSP No. 115-1 had no impact on the results of operations, cash flows, or financial condition of the Company as all losses have been and continue to be recorded through a regulatory liability, whether realized, unrealized, or identified as other-than-temporary. Details of the securities held in these trusts at December 31, 2007 were as follows:
The contractual maturities of debt securities at December 31, 2007 are as follows: $33.1 million in 2008; $28.8 million in 2009-2012; $17.0 million in 2013-2017; and $65.8 million thereafter.
Sales of the securities held in the trust funds resulted in cash proceeds of $333.4 million, $285.7 million, and $223.8 million in 2007, 2006, and 2005, respectively, all of which were re-invested. Realized gains and other-than-temporary impairment losses were $34.6 million and $37.2 million, respectively, in 2007 and $22.0 million and $18.2 million, respectively, in 2006. Net realized gains were $9.9 million in 2005. Realized gains and other-than-temporary impairment losses are determined on a specific identification basis. In accordance with regulatory guidance, all realized and unrealized gains and losses are included in the regulatory liability for asset retirement obligations in the balance sheets and are not included in net income or other comprehensive income. Unrealized gains and other-than-temporary impairment losses are considered non-cash transactions for purposes of the statements of cash flows.
Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the Alabama PSC. The NRC’s minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC. At December 31, 2007, the accumulated provisions for decommissioning were as follows:
Site study cost is the estimate to decommission the facility as of the site study year. The estimated costs of decommissioning, based on the most current study performed in 2003 for Plant Farley were as follows:
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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.
All of the Company’s decommissioning costs for ratemaking are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and a trust earnings rate of 7.0%. Another significant assumption used was the change in the operating license for Plant Farley.
In May 2005, the NRC granted the Company a 20-year extension of the operating license for both units at Plant Farley. As a result of the license extension, amounts previously contributed to the external trust are currently projected to be adequate to meet the decommissioning obligations. Therefore, in June 2005, the Alabama PSC approved the Company’s request to suspend, effective January 1, 2005, the inclusion in its annual cost of service of $18 million in decommissioning costs and to also suspend the associated obligation to make semi-annual contributions to the external trust. The Company will continue to provide site specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC’s approval to address any changes in a manner consistent with the NRC and other applicable requirements. The approved suspension does not affect the transfer of internal reserves (less than $1 million annually) previously collected from customers prior to the establishment of the external trust.
Allowance for Funds Used During Construction (AFUDC)
In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. The equity component of AFUDC is not included in calculating taxable income. All current construction costs are included in retail rates. The composite rate used to determine the amount of AFUDC was 9.4% in 2007, 8.8% in 2006, and 8.8% in 2005. AFUDC, net of income tax, as a percent of net income after dividends on preferred and preference stock was 8.0% in 2007, 4.5% in 2006, and 5.0% in 2005.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Natural Disaster Reserve
In accordance with an Alabama PSC order, the Company has established a natural disaster reserve (NDR) to cover the cost of uninsured damages from major storms to transmission and distribution facilities. The Company collects a monthly NDR charge per account that consists of two components which began on January 1, 2006. The first component is intended to establish and maintain a reserve for future storms and is an on-going part of customer billing. This plan has a target reserve balance of $75 million that could be achieved in four years assuming the Company experiences no additional storms. The second component of the NDR charge is intended to allow recovery of any existing deferred hurricane related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives the Company authority to have a negative NDR balance when costs of uninsured storm damage exceed any established NDR balance. Absent further Alabama PSC approval, the maximum total NDR charge consisting of both components is $10 per month per account for non-residential customers and $5 per month per account for residential customers.
At December 31, 2007, the Company had accumulated a balance of $26.1 million in the target reserve for future storms, which is included in the balance sheets under “Other Regulatory Liabilities.” In June 2007, the Company fully recovered its prior storm cost
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of $51.3 million resulting from Hurricanes Dennis and Katrina. As a result, customer rates decreased by this portion of the NDR charge effective July 1, 2007.
As revenue from the NDR charge is recognized, an equal amount of operations and maintenance expense related to the NDR will also be recognized. As a result, this increase in revenue and expense will not have an impact on net income, but will increase annual cash flow.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
Fuel Inventory
Fuel inventory includes the average costs of oil, coal, and natural gas. Fuel is charged to inventory when purchased and then expensed as used and recovered by the Company through fuel cost recovery rates approved by the Alabama PSC. Emission allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.
Stock Options
Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. Prior to January 1, 2006, the Company accounted for options granted in accordance with Accounting Principles Board Opinion No. 25; thus, no compensation expense was recognized because the exercise price of all options granted equaled the fair market value on the date of the grant.
Effective January 1, 2006, the Company adopted the fair value recognition provisions of FASB Statement No. 123(R), “Share-Based Payment” (SFAS No. 123(R)), using the modified prospective method. Under that method, compensation cost for the years ended December 31, 2007 and 2006 was recognized as the requisite service was rendered and included: (a) compensation cost for the portion of share-based awards granted prior to and that were outstanding as of January 1, 2006, for which the requisite service had not been rendered, based on the grant-date fair value of those awards as calculated in accordance with the original provisions of FASB Statement No. 123, “Accounting for Stock-Based Compensation”, and (b) compensation cost for all share-based awards granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123(R). Results for prior periods have not been restated.
The compensation cost and tax benefits related to the grant and exercise of Southern Company stock options to the Company’s employees are recognized in the Company’s financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company.
For the Company, the adoption of SFAS No. 123(R) has resulted in a reduction in earnings before income taxes and net income of $4.9 million and $3.0 million, respectively, for the year ended December 31, 2007 and $4.8 million and $3.0 million, respectively, for the year ended December 31, 2006. Additionally, SFAS No. 123(R) requires the gross excess tax benefit from stock option exercises be reclassified as a financing cash flow as opposed to an operating cash flow; the reduction in operating cash flows and the increase in financing cash flows for the years ended December 31, 2007 and December 31, 2006 was $2.6 million and $1.3 million, respectively.
For the year ended December 31, 2005, prior to the adoption of SFAS No. 123(R), the pro forma impact on net income of fair-value accounting for options granted was as follows:
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Because historical forfeitures have been insignificant and are expected to remain insignificant, no forfeitures were assumed in the calculation of compensation expense; rather they are recognized when they occur.
The estimated fair values of stock options granted in 2007, 2006, and 2005 were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company’s stock over a period equal to the expected term. The Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted:
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities and are measured at fair value. Substantially all of the Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are exempt from fair value accounting requirements and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the Alabama PSC-approved fuel hedging program. This results in the deferral of related gains and losses in other comprehensive income or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income.
The Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk.
The Company’s other financial instruments for which the carrying amounts did not equal fair values at December 31 were as follows:
The fair values were based on either closing market prices or closing prices of comparable instruments.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and prior to the adoption of SFAS No.158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS No. 158) the minimum pension liability, less income taxes and reclassifications for amounts included in net income.
Variable Interest Entities
The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. The Company has established certain wholly-owned trusts to issue preferred securities. See Note 6 under “Long-Term Debt Payable to Affiliated Trusts” for additional information. However, the Company is not considered the primary beneficiary of the trusts. Therefore, the investments in
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these trusts are reflected as Other Investments, and the related loans from the trusts are included in Long-term Debt in the balance sheets.
Investments
The Company maintains an investment in a debt security that matures in 2018 and is classified as available-for-sale. This security is included in the balance sheets under Other Property and Investments-Other and totaled $2.3 million and $2.6 million at December 31, 2007 and 2006, respectively. Because the interest rate resets weekly, the carrying value approximates the fair market value.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the plan are expected for the year ending December 31, 2008. The Company also provides certain defined benefit pension plans for a selected group of management and highly-compensated employees. Benefits under these non-qualified plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds trusts to the extent required by the Alabama PSC and the FERC. For the year ending December 31, 2008, postretirement trust contributions are expected to total approximately $22.9 million.
The measurement date for plan assets and obligations is September 30 for each year presented. Pursuant to SFAS No. 158, the Company will be required to change the measurement date for its defined benefit postretirement plans from September 30 to December 31 beginning with the year ending December 31, 2008.
Pension Plans
The total accumulated benefit obligation for the pension plans was $1.3 billion in 2007 and 2006. Changes during the year in the projected benefit obligations and fair value of plan assets were as follows:
At December 31, 2007, the projected benefit obligations for the qualified and non-qualified pension plans were $1.3 billion and $91 million, respectively. All plan assets are related to the qualified pension plan.
Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large
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losses through diversification but also monitors and manages other aspects of risk. The actual composition of the Company’s pension plan assets as of the end of the year, along with the targeted mix of assets, is presented below:
Amounts recognized in the balance sheets related to the Company’s pension plans consist of:
Presented below are the amounts included in regulatory assets and regulatory liabilities at December 31, 2007 and December 31, 2006 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 2008:
The changes in the balances of regulatory assets and regulatory liabilities related to the defined benefit pension plans for the year ended December 31, 2007 are presented in the following table:
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Components of net periodic pension cost (income) were as follows:
Net periodic pension cost (income) is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2007, estimated benefit payments were as follows:
Other Postretirement Benefits
Changes during the year in the accumulated postretirement benefit obligations (APBO) and in the fair value of plan assets were as follows:
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Other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk. The actual composition of the Company’s other postretirement benefit plan assets as of the end of the year, along with the targeted mix of assets, is presented below:
Amounts recognized in the balance sheets related to the Company’s other postretirement benefit plans consist of:
Presented below are the amounts included in regulatory assets at December 31, 2007 and December 31, 2006 related to the other postretirement benefit plans that had not yet been recognized in net periodic postretirement benefit cost along with the estimated amortization of such amounts for 2008.
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The change in the balance of regulatory assets related to the other postretirement benefit plans for the year ended December 31, 2007 is presented in the following table:
Components of the other postretirement benefit plans’ net periodic cost were as follows:
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced the Company’s expenses for the years ended December 31, 2007, 2006, and 2005 by approximately $10.7 million, $11.1 million, and $8.7 million, respectively.
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the postretirement plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows:
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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 2004, for the 2005 plan year, using a discount rate of 5.75%.
The Company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.
An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 9.75% for 2008, decreasing gradually to 5.25% through the year 2015, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2007 as follows:
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution up to 6% of an employee’s base salary. Prior to November 2006, the Company matched employee contributions at a rate of 75% up to 6% of the employee’s base salary. Total matching contributions made to the plan for 2007, 2006, and 2005 were $17 million, $14 million, and $14 million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements.
Environmental Matters
New Source Review Actions
In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including the Company, alleging that it had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against the Company in the U.S. District Court for the Northern District of Alabama after the Company was dismissed from the original action. In these lawsuits, the EPA alleged that NSR violations occurred at five coal-fired generating facilities operated by the Company. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units.
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In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between the Company and the EPA, resolving the alleged NSR violations at Plant Miller. The consent decree required the Company to pay $100,000 to resolve the government’s claim for a civil penalty and to donate $4.9 million of sulfur dioxide emission allowances to a nonprofit charitable organization and formalized specific emissions reductions to be accomplished by the Company, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in Alabama granted the Company’s motion for summary judgment and entered final judgment in favor of the Company on the EPA’s claims related to all of the remaining plants: Plants Barry, Gaston, Gorgas, and Greene County.
The plaintiffs appealed the district court’s decision to the U.S. Court of Appeals for the Eleventh Circuit, and the appeal was stayed by the Appeals Court pending the U.S. Supreme Court’s decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke Energy case in April 2007. On October 5, 2007, the U.S. District Court for the Northern District of Alabama issued an order in the Company’s case indicating a willingness to re-evaluate its previous decision in light of the Supreme Court’s Duke Energy opinion. On December 21, 2007, the Eleventh Circuit vacated the district court’s decision in the Company’s case and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court’s decision in the Duke Energy case. The final outcome of these matters cannot be determined at this time.
The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in this matter could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
Carbon Dioxide Litigation
In July 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and no decision has been issued. The ultimate outcome of these matters cannot be determined at this time.
Environmental Remediation
The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. The Company has received authority from the Alabama PSC to recover approved environmental compliance costs through a specific retail rate clause that is adjusted annually. See “Retail Regulatory Matters - Rate CNP” herein for additional information.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.
In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales by the Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level.
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In late June and July 2007, hearings were held in this proceeding and the presiding administrative law judge issued an initial decision on November 9, 2007 regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the Company to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates and could also result in refunds of up to $3.9 million, plus interest. The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter.
On June 21, 2007, the FERC issued its final rule regarding market-based rate authority. The FERC generally retained its current market-based rate standards. The impact of this order and its effect on the generation dominance proceeding cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet is operated under the Intercompany Interchange Contract (IIC), as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies (including the Company), Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct.
In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms and Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. Southern Company filed with the FERC in November 2006 a compliance plan in connection with the order. On April 19, 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan is not expected to have a material impact on the Company’s financial statements. On November 19, 2007, Southern Company notified the FERC that the plan had been implemented and the FERC division of audits subsequently began an audit pertaining to compliance implementation and related matters, which is ongoing.
Generation Interconnection Agreements
In November 2004, generator company subsidiaries of Tenaska, Inc. (Tenaska), as counterparties to two previously executed interconnection agreements with the Company, filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $11 million previously paid for interconnection facilities. No other similar complaints are pending with the FERC.
On January 19, 2007, the FERC issued an order granting Tenaska’s requested relief. Although the FERC’s order required the modification of Tenaska’s interconnection agreements, under the provisions of the order, the Company determined that no refund was payable to Tenaska. Southern Company requested rehearing asserting that the FERC retroactively applied a new principle to existing interconnection agreements. Tenaska requested rehearing of FERC’s methodology for determining the amount of refunds. The requested rehearings were denied and Southern Company and Tenaska have appealed the orders to the U.S. Circuit Court for the District of Columbia. The final outcome of this matter cannot now be determined.
Retail Regulatory Matters
The following retail ratemaking procedures will remain in effect until the Alabama PSC votes to modify or discontinue them.
Rate RSE
The Alabama PSC has adopted a Rate Stabilization and Equalization plan (Rate RSE) that provides for periodic annual adjustments based upon the Company’s earned return on retail common equity. Retail rates remain unchanged when the retail return on common equity ranges between 13.0% and 14.5%. In October 2005, the Alabama PSC approved a revision to Rate RSE. Prior to January 2007, annual adjustments were limited to 3.0%. Effective January 2007 and thereafter, Rate RSE adjustments are made based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged
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together, cannot exceed 4.0% per year and any annual adjustment is limited to 5.0%. Retail rates remain unchanged when the return on retail common equity is projected to be between 13.0% and 14.5%. If the Company’s actual retail return on common equity is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return on common equity fall below the allowed equity return range. On November 30, 2007, the Company made its submission of projected data for calendar year 2008. The Rate RSE increase for 2008 is 3.24%, or $147 million annually, and was effective in January 2008. Under the terms of Rate RSE, the maximum increase for 2009 cannot exceed 4.76%. See “Rate CNP” for additional information.
Rate CNP
The Company’s retail rates, approved by the Alabama PSC, also provide for adjustments to recognize the placing of new generating facilities into retail service and the recovery of retail costs associated with certificated PPAs under Rate CNP. In April 2005, an annual adjustment to Rate CNP decreased retail rates by approximately 0.5%, or $19 million annually. The annual true-up adjustment effective in April 2006 increased retail rates by 0.5%, or $19 million annually. There was no rate adjustment associated with the annual true-up adjustment in April 2007 and there will be no adjustment to the current Rate CNP to recover certificated PPA costs in April 2008.
Rate CNP also allows for the recovery of the Company’s retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism, based on forward looking information, began operation in January 2005 and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on invested capital. Retail rates increased due to environmental costs approximately 1.0% in January 2005, 1.2% in January 2006, 0.6% in January 2007, and 2.4% in January 2008.
Fuel Cost Recovery
The Company has established fuel cost recovery rates under an energy cost recovery clause (Rate ECR) approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. The Company, along with the Alabama PSC, will continue to monitor the under recovered fuel cost balance to determine whether an additional adjustment to billing rates is required.
In June 2007, the Alabama PSC ordered the Company to increase its Rate ECR factor to 3.100 cents per kilowatt-hour (KWH) effective with billings beginning July 2007 for the 30-month period ending December 2009. The previous rate of 2.400 cents per KWH had been in effect since January 2006. This increase was intended to permit recovery of energy costs based on an estimate of future energy cost, as well as the collection of the existing under recovered energy cost by the end of 2009. During the 30-month period, the Company will be allowed to include a carrying charge associated with the under recovered fuel costs in the fuel expense calculation. In the event the application of this increased Rate ECR factor results in an over recovered position during this period, the Company will pay interest on any such over recovered balance at the same rate used to derive the carrying cost.
The Company’s under recovered fuel costs as of December 31, 2007 totaled $279.8 million as compared to $301.0 million at December 31, 2006. As a result of the Alabama PSC order, the Company classified $81.7 million and $301.0 million of the under recovered regulatory clause revenues as deferred charges and other assets in the balance sheets as of December 31, 2007 and December 31, 2006, respectively. This classification is based on an estimate which includes such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of the recovery of the under recovered fuel costs.
Natural Disaster Cost Recovery
In February and December 2005, the Company requested and received Alabama PSC approval of an accounting order that allowed the Company to immediately return certain regulatory liabilities to the retail customers. These orders also allowed the Company to simultaneously recover from customers an accrual of approximately $48 million primarily to offset the costs of Hurricane Ivan and restore a positive balance in the NDR. The combined effect of these orders had no impact on the Company’s net income in 2005.
In July 2005 and August 2005, Hurricanes Dennis and Katrina, respectively, hit the coast of Alabama and continued north through the state, causing significant damage in parts of the service territory of the Company. Approximately 241,000 and 637,000 of the Company’s 1.4 million customer accounts were without electrical service immediately after Hurricanes Dennis and Katrina, respectively. The Company sustained significant damage to its distribution and transmission facilities during these storms.
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In August 2005, the Company received approval from the Alabama PSC to defer the Hurricane Dennis storm-related operations and maintenance costs (approximately $28 million). In October 2005, the Company also received similar approval from the Alabama PSC to defer the Hurricane Katrina storm-related operations and maintenance costs (approximately $30 million). The NDR balance at December 31, 2005 was a regulatory asset of $50.6 million.
In December 2005, the Alabama PSC approved a request by the Company to replenish the depleted NDR and allow for recovery of future natural disaster costs. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of uninsured storm damage exceed any established reserve balance. The order also approved a separate monthly NDR charge consisting of two components which began in January 2006. The first component is intended to establish and maintain a target reserve balance of $75 million for future storms and is an on-going part of customer billing. The Company currently expects that the target reserve balance could be achieved within four years. The second component of the NDR charge is intended to allow recovery of the existing deferred hurricane related operations and maintenance costs and any future reserve deficits over a 24-month period. Absent further Alabama PSC approval, the maximum total NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account.
At December 31, 2007, the Company had accumulated a balance of $26.1 million in the target reserve for future storms, which is included in the balance sheets under “Other Regulatory Liabilities.” In June 2007, the Company fully recovered its prior storm cost of $51.3 million resulting from Hurricanes Dennis and Katrina. As a result, customer rates decreased by this portion of the NDR charge effective in July 2007.
As revenue from the NDR charge is recognized, an equal amount of operations and maintenance expense related to the NDR will also be recognized. As a result, this increase in revenue and expense will not have an impact on net income, but will increase annual cash flow.
4. JOINT OWNERSHIP AGREEMENTS
The Company and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 megawatts, as well as associated transmission facilities. The capacity of these units is sold equally to the Company and Georgia Power under a contract which, in substance, requires payments sufficient to provide for the operating expenses, taxes, interest expense, and a return on equity, whether or not SEGCO has any capacity and energy available. The term of the contract extends automatically for two-year periods, subject to either party’s right to cancel upon two year’s notice. The Company’s share of purchased power totaled $105 million in 2007, $95 million in 2006, and $90 million in 2005 and is included in “Purchased power from affiliates” in the statements of income. The Company accounts for SEGCO using the equity method.
In addition, the Company has guaranteed unconditionally the obligation of SEGCO under an installment sale agreement for the purchase of certain pollution control facilities at SEGCO’s generating units, pursuant to which $24.5 million principal amount of pollution control revenue bonds are outstanding. Also, the Company has guaranteed $50 million principal amount of unsecured senior notes issued by SEGCO for general corporate purposes. Georgia Power has agreed to reimburse the Company for the pro rata portion of such obligations corresponding to its then proportionate ownership of stock of SEGCO if the Company is called upon to make such payment under its guaranty.
At December 31, 2007, the capitalization of SEGCO consisted of $66 million of equity and $104 million of debt on which the annual interest requirement is $3.2 million. SEGCO paid dividends totaling $2.6 million in 2007, $8.5 million in 2006, and $7.7 million in 2005, of which one-half of each was paid to the Company. In addition, the Company recognizes 50% of SEGCO’s net income.
In addition to the Company’s ownership of SEGCO, the Company’s percentage ownership and investment in jointly-owned coal-fired generating plants at December 31, 2007 is as follows:
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(1)
Jointly owned with an affiliate, Mississippi Power.
(2)
Jointly owned with Alabama Electric Cooperative, Inc.
At December 31, 2007, the Company’s Plant Miller portion of construction work in progress was $49.1 million.
The Company has contracted to operate and maintain the jointly owned facilities as agent for their co-owners. The Company’s proportionate share of its plant operating expenses is included in operating expenses in the statements of income.
5. INCOME TAXES
Southern Company files a consolidated federal income tax return and combined income tax returns for the State of Georgia, State of Mississippi, and the State of Alabama. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability.
In 2005, in order to avoid the loss of certain federal income tax credits related to the production of synthetic fuel, Southern Company chose to defer certain deductions otherwise available to the subsidiaries. The cash flow benefit associated with the utilization of the tax credits was allocated to the subsidiary that otherwise would have claimed the available deductions on a separate company basis without the deferral. This allocation concurrently reduced the tax benefit of the credits allocated to those subsidiaries that generated the credits. As the deferred expenses are deducted, the benefit of the tax credits will be repaid to the subsidiaries that generated the tax credits. At December 31, 2007 and 2006, the Company had $32.0 million and $34.9 million in accumulated deferred income taxes and $2.9 million and $3.1 million in accrued taxes - income taxes, respectively, payable to these subsidiaries, on the balance sheets.
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
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:
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At December 31, 2007, the Company’s tax-related regulatory assets and liabilities were $347 million and $94 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest. These liabilities are attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized investment tax credits.
In accordance with regulatory requirements, deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $8.0 million in 2007, $8.0 million in 2006, and $8.8 million in 2005. At December 31, 2007, all investment tax credits available to reduce federal income taxes payable had been utilized.
Effective Tax Rate
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
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In accordance with Alabama PSC orders, the Company returned approximately $30 million of excess deferred income taxes to its ratepayers in 2005, resulting in 3.6% of the “Difference in prior years’ deferred and current tax rates” in the table above. See Note 3 to the financial statements under “Retail Regulatory Matters - Natural Disaster Cost Recovery” for additional information.
The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to United States production activities as defined in Internal Revenue Code Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for years 2007 through 2009, and a 9% rate applicable for all years after 2009. The increase from 3% in 2006 to 6% in 2007 was one of several factors that increased the Company’s 2007 deduction by $7.8 million over the 2006 deduction. The resulting additional tax benefit was over $3 million.
Unrecognized Tax Benefits
On January 1, 2007, the Company adopted FIN 48 which requires companies to determine whether it is “more likely than not” that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. It also provides guidance on the recognition, measurement, and classification of income tax uncertainties, along with any related interest and penalties.
Prior to the adoption of FIN 48, the Company had unrecognized tax benefits, which were previously accrued under SFAS No. 5, “Accounting for Contingencies,” of approximately $1.2 million. The total $1.2 million in unrecognized tax benefits would impact the Company’s effective tax rate if recognized. For 2007, the total amount of unrecognized tax benefits increased by $3.6 million, resulting in a balance of $4.8 million as of December 31, 2007.
Changes during the year in unrecognized tax benefits were as follows:
Impact on the Company’s effective tax rate, if recognized, is as follows:
Accrued interest for unrecognized tax benefits:
The Company classifies interest on tax uncertainties as interest expense. Net interest accrued for the year ended December 31, 2007 was $0.4 million. The Company did not accrue any penalties on uncertain tax positions.
The IRS has audited and closed all tax returns prior to 2004. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2002.
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It is reasonably possible that the amount of the unrecognized benefit with respect to certain of the Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The possible settlement of the production activities deduction methodology and/or the conclusion or settlement of federal or state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
6. FINANCING
Long-Term Debt Payable to Affiliated Trusts
The Company has formed certain wholly owned trust subsidiaries for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to the Company through the issuance of junior subordinated notes totaling $206 million, which constitute substantially all assets of these trusts and are reflected in the balance sheets as Long-term Debt Payable. The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective trusts’ payment obligations with respect to these securities. At December 31, 2007, preferred securities of $200 million were outstanding. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities.
Pollution Control Bonds
Pollution control obligations represent loans to the Company from public authorities of funds or installment purchases of pollution control facilities financed by funds derived from sales by public authorities of revenue bonds. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The Company incurred obligations related to the issuance of $265.5 million of tax-exempt bonds in 2007. Proceeds from certain issuances are restricted until expenditures are incurred.
Senior Notes
The Company issued a total of $850 million of unsecured senior notes in 2007. The proceeds of these issuances were used to repay short-term indebtedness and for other general corporate purposes.
At December 31, 2007 and 2006, the Company had $4.1 billion and $4.0 billion, respectively, of senior notes outstanding. These senior notes are subordinate to all secured debt of the Company which amounted to approximately $153 million at December 31, 2007.
Subsequent to December 31, 2007, the Company issued $300 million of long-term senior notes. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.
Preference and Common Stock
In 2007, the Company issued eight million new shares of preference stock at $25.00 stated capital per share and realized proceeds of $200 million. In addition, the Company issued 5.725 million new shares of common stock to Southern Company at $40.00 per share and realized proceeds of $229 million. The proceeds of these issuances were used to repay short-term indebtedness and for other general corporate purposes.
Subsequent to December 31, 2007, the Company redeemed 1,250 shares of its Flexible Money Market Class A Preferred Stock (Series 2003A), Stated Capital $100,000 Per Share ($125 million aggregate value).
Outstanding Classes of Capital Stock
The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized and outstanding. The Company’s preferred stock and Class A preferred stock, without preference between classes, rank senior to the Company’s preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. The Company’s preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. Certain series of the preferred stock, Class A preferred stock, and preference stock are subject to redemption at the option of the Company on or after a specified date (typically 5 or 10 years after the date of issuance).
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Dividend Restrictions
The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
Securities Due Within One Year
At December 31, 2007, the Company had scheduled maturities and redemptions of senior notes and preferred stock due within one year totaling $535 million. At December 31, 2006, the Company had scheduled maturities and redemptions of senior notes due within one year totaling $669 million.
Debt maturities through 2012 applicable to total long-term debt are as follows: $410 million in 2008; $250 million in 2009; $100 million in 2010; $200 million in 2011; and $200 million in 2012.
Assets Subject to Lien
In 2006, the Company discharged its remaining outstanding first mortgage bond obligations and the direct first lien on substantially all of the Company’s fixed property and franchises was removed. The Company has granted liens on certain property in connection with the issuance of certain series of pollution control bonds with an outstanding principal amount of $153 million, as of December 31, 2007.
Bank Credit Arrangements
The Company maintains committed lines of credit in the amount of $1.2 billion (including $582 million of such lines which are dedicated to funding purchase obligations relating to variable rate pollution control bonds), of which $435 million will expire at various times during 2008. $355 million of the credit facilities expiring in 2008 allow for the execution of one-year term loans. $800 million of credit facilities expire in 2012.
Most of the credit arrangements require payment of a commitment fee based on the unused portion of the commitment or the maintenance of compensating balances with the banks. Commitment fees are less than one-fourth of 1% for the Company. Compensating balances are not legally restricted from withdrawal.
Most of the Company’s credit arrangements with banks have covenants that limit the Company’s debt to 65% of total capitalization, as defined in the arrangements. For purposes of calculating these covenants, long-term notes payable to affiliated trusts are excluded from debt but included in capitalization. Exceeding this debt level would result in a default under the credit arrangements. At December 31, 2007, the Company was in compliance with the debt limit covenants. In addition, the credit arrangements typically contain cross default provisions that would be triggered if the Company defaulted on other indebtedness (including guarantee obligations) above a specified threshold. None of the arrangements contain material adverse change clauses at the time of borrowings.
The Company borrows through commercial paper programs that have the liquidity support of committed bank credit arrangements. In addition, the Company borrows from time to time through extendible commercial note programs and uncommitted credit arrangements. As of December 31, 2007, the Company had no commercial paper or extendible commercial notes outstanding. As of December 31, 2006, the Company had $120 million of commercial paper outstanding, and no extendible commercial notes outstanding. During 2007 and 2006, the peak amount outstanding for short-term borrowings was $214 million and $411 million, respectively. The average amount outstanding in 2007 and 2006 was $36 million and $45 million, respectively. The average annual interest rate on short-term borrowings in 2007 was 5.34% and in 2006 was 4.76%. Short-term borrowings are included in notes payable in the balance sheets.
At December 31, 2007, the Company had regulatory approval to have outstanding up to $2.0 billion of short-term borrowings.
Financial Instruments
The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company has implemented fuel-hedging programs at the instruction of the Alabama PSC. The Company also enters into hedges of forward electricity sales. There was no material ineffectiveness recorded in earnings in 2007, 2006, and 2005.
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At December 31, 2007, the fair value gains/(losses) of derivative energy contracts were reflected in the financial statements as follows:
The fair value gain or loss for hedges that are recoverable through the regulatory fuel clauses are recorded in the regulatory assets and liabilities and are recognized in earnings at the same time the hedged items affect earnings. The Company has energy-related hedges in place up to and including 2010.
The Company also enters into derivatives to hedge exposure to changes in interest rates. Derivatives related to variable rate securities or forecasted transactions are accounted for as cash flow hedges. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. As such, no material ineffectiveness has been recorded in earnings for any period presented.
At December 31, 2007, the Company had $246 million notional amount of interest rate derivatives outstanding that related to variable rate tax exempt debt, with net fair value loss of $1.4 million as follows:
*
Hedged using the Securities Industry and Financial Markets Association Municipal Swap Index (SIFMA), (Formerly the Bond Market Association/PSA Municipal Swap Index)
Subsequent to December 31, 2007, the Company entered into $330 million notional amounts of interest rate swaps related to variable rate tax exempt debt, to hedge changes in interest rates beginning in February 2008 through February 2010. The weighted average fixed payment rate on these hedges is 2.49%.
The fair value gain or loss for cash flow hedges is recorded in other comprehensive income and is reclassified into earnings at the same time the hedged items affect earnings. In 2007, 2006, and 2005, the Company settled gains (losses) of $(6.2) million, $18.0 million, and $(21.4) million, respectively, upon termination of certain interest derivatives at the same time it issued debt. The effective portions of these gains (losses) have been deferred in other comprehensive income and will be amortized to interest expense over the life of the original interest derivative, which approximates to the related underlying debt.
For the years 2007, 2006, and 2005, approximately $(0.8) million, $9.8 million, and $3.5 million, respectively, of pre-tax gains (losses) were reclassified from other comprehensive income to interest expense. For 2008, pre-tax losses of approximately $0.2 million are expected to be reclassified from other comprehensive income to interest expense. The Company has interest-related hedges in place through 2010 and has gains (losses) that are being amortized through 2035.
7. COMMITMENTS
Construction Program
The Company is engaged in continuous construction programs, currently estimated to total $1.6 billion in 2008, $1.6 billion in 2009, and $1.0 billion in 2010. These amounts include $60 million, $50 million, and $42 million in 2008, 2009, and 2010, respectively, for construction expenditures related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included under “Fuel Commitments.” The construction programs are subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include: changes in business conditions; revised load growth estimates; changes in environmental statutes and regulations; changes in existing nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; increasing costs of labor, equipment, and materials; and
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Alabama Power Company 2007 Annual Report
cost of capital. At December 31, 2007, significant purchase commitments were outstanding in connection with the construction program. The Company has no generating plants under construction. Construction of new transmission and distribution facilities and capital improvements, including those needed to meet environmental standards for existing generation, transmission, and distribution facilities, will continue.
Long-Term Service Agreements
The Company has entered into Long-Term Service Agreements (LTSAs) with General Electric (GE) for the purpose of securing maintenance support for its combined cycle and combustion turbine generating facilities. The LTSAs provide that GE will perform all planned inspections on the covered equipment, which includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in each contract.
In general, these LTSAs are in effect through two major inspection cycles per unit. Scheduled payments to GE, which are subject to price escalation, are made at various intervals based on actual operating hours of the respective units. Total remaining payments to GE under these agreements for facilities owned are currently estimated at $136 million over the remaining life of the agreements, which are currently estimated to range up to 9 years. However, the LTSAs contain various cancellation provisions at the option of the Company. Payments made to GE prior to the performance of any planned maintenance are recorded as either prepayments or other deferred charges and assets in the balance sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed.
Purchased Power Commitments
The Company has entered into various long-term commitments for the purchase of electricity. Total estimated minimum long-term obligations at December 31, 2007 were as follows:
Limestone Commitments
As part of the Company’s program to reduce sulfur dioxide emissions from certain of its coal plants, the Company is constructing certain equipment and has entered into various long-term commitments for the procurement of limestone to be used in such equipment. Contracts are structured with tonnage minimums and maximums in order to account for changes in coal burn and sulfur content. The Company has a minimum contractual obligation of 3.1 million tons equating to approximately $127 million through 2019. Estimated expenditures over the next five years are $2 million in 2008, $3 million in 2009, $11 million in 2010, $14 million in 2011, and $14 million in 2012.
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide emission allowances. Natural gas purchase commitments contain fixed volumes with prices based on various indices at the time of delivery. Amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2007. Total estimated minimum long-term commitments at December 31, 2007 were as follows:
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Alabama Power Company 2007 Annual Report
Additional commitments for fuel will be required to supply the Company’s future needs. Total charges for nuclear fuel included in fuel expense totaled $65 million in 2007, $66 million in 2006, and $64 million in 2005.
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. The creditworthiness of Southern Power is currently inferior to the creditworthiness of the traditional operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.
Operating Leases
The Company has entered into rental agreements for coal rail cars, vehicles, and other equipment with various terms and expiration dates. These expenses totaled $27.7 million in 2007, $30.3 million in 2006, and $27.3 million in 2005. Of these amounts, $20.5 million, $21.5 million, and $17.8 million for 2007, 2006, and 2005, respectively, relate to the rail car leases and are recoverable through the Company’s Rate ECR. At December 31, 2007, estimated minimum rental commitments for non-cancelable operating leases were as follows:
In addition to the rental commitments above, the Company has potential obligations upon expiration of certain leases with respect to the residual value of the leased property. These leases expire in 2009 and 2010, and the Company’s maximum obligations are $19.5 million and $62.2 million, respectively. At the termination of the leases, at the Company’s option, the Company may negotiate an extension, exercise its purchase option, or the property can be sold to a third party. The Company expects that the fair market value of the leased property would substantially eliminate the Company’s payments under the residual value obligations.
Guarantees
At December 31, 2007, the Company had outstanding guarantees related to SEGCO’s purchase of certain pollution control facilities and issuance of senior notes, as discussed in Note 4, and to certain residual values of leased assets as described above in “Operating Leases.”
8. STOCK OPTION PLAN
Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. As of December 31, 2007, 1,184 current and former employees of the Company participated in the stock
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Alabama Power Company 2007 Annual Report
option plan. The maximum number of shares of common stock that may be issued under this plan may not exceed 40 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. For certain stock option awards, a change in control will provide accelerated vesting.
The Company’s activity in the stock option plan for 2007 is summarized below:
The number of stock options vested and expected to vest in the future, as of December 31, 2007 was not significantly different from the number of stock options outstanding at December 31, 2007 as stated above. As of December 31, 2007, the weighted average remaining contractual term for the options outstanding and options exercisable was 6.4 years and 5.3 years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $51.0 million and $42.7 million, respectively.
As of December 31, 2007, there was $1.4 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 10 months.
The total intrinsic value of options exercised during the years ended December 31, 2007, 2006, and 2005 was $9.7 million, $4.9 million, and $21.9 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $3.7 million, $1.9 million, and $8.5 million, respectively, for the years ended December 31, 2007, 2006, and 2005.
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 $10.8 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $300 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors. The Company could be assessed up to $101 million per incident for each licensed reactor it operates but not more than an aggregate of $15 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company is $201 million per incident but not more than an aggregate of $30 million to be paid for each incident in any one year. 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 on or before August 31, 2008.
The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members’ nuclear generating facilities.
Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.3 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.
NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member’s nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. The Company purchases the maximum limit allowed by NEIL and has elected a 12-week waiting period.
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Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for the Company under the NEIL policies would be $37 million.
Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12 month period is $3.2 billion plus such additional amounts NEIL, can recover through reinsurance, indemnity, or other sources.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.
All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.
10. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for 2007 and 2006 are as follows:
The Company’s business is influenced by seasonal weather conditions.
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SELECTED FINANCIAL AND OPERATING DATA 2003-2007
Alabama Power Company 2007 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA 2003-2007 (continued)
Alabama Power Company 2007 Annual Report
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GEORGIA POWER COMPANY
FINANCIAL SECTION
II-161
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Georgia Power Company 2007 Annual Report
The management of Georgia Power Company (the “Company”) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Under management’s supervision, an evaluation of the design and effectiveness of the Company’s internal control over financial reporting was conducted based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2007.
This Annual Report does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report.
/s/ Michael D. Garrett
Michael D. Garrett
President and Chief Executive Officer
/s/ Cliff S. Thrasher
Cliff S. Thrasher
Executive Vice President, Chief Financial Officer, and Treasurer
February 25, 2008
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Georgia Power Company
We have audited the accompanying balance sheets and statements of capitalization of Georgia Power Company (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2007 and 2006, 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, 2007. 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 II-186 to II-223) present fairly, in all material respects, the financial position of Georgia Power Company at December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 5 to the financial statements, in 2007 the Company changed its method of accounting for uncertainty in income taxes. As discussed in Note 2 to the financial statements, in 2006 the Company changed its method of accounting for the funded status of defined benefit pension and other postretirement plans.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 25, 2008
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Georgia Power Company 2007 Annual Report
OVERVIEW
Business Activities
Georgia Power Company (the Company) operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and 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 stable regulatory environment, to achieve energy sales growth, and to effectively manage and secure timely recovery of rising costs. These costs include those related to growing demand, increasingly stringent environmental standards, and fuel prices. In December 2007, the Company completed a major retail rate proceeding (2007 Retail Rate Plan) that should provide earnings stability over the term of the 2007 Retail Rate Plan. This regulatory action also enables the recovery of substantial capital investments to facilitate the continued reliability of the transmission and distribution networks, continued generation and other investments as well as the recovery of increased operating costs. The 2007 Retail Rate Plan includes a tariff specifically for the recovery of costs related to environmental controls mandated by state and federal regulations. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future. The Company is required to file a general rate case by July 1, 2010, which will determine whether the 2007 Retail Rate Plan should be continued, modified, or discontinued. The Company also received regulatory orders to increase its fuel cost recovery rate effective June 1, 2005, July 1, 2006, and March 1, 2007. The Company is required to file its next fuel cost recovery case by March 1, 2008.
Key Performance Indicators
In striving to maximize shareholder value while providing cost-effective energy to more than two million customers, the Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. The Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company’s results.
Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. The 2007 fossil/hydro Peak Season EFOR of 2.23% was better than target. The nuclear generating fleet also uses Peak Season EFOR as an indicator of availability and efficient generation fleet operations during the peak season. The 2007 nuclear Peak Season EFOR of 1.23% was also better than target. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected capital expenditures. The 2007 performance was better than target for these reliability measures. Net income after dividends on preferred and preference stock is the primary component of the Company’s contribution to Southern Company’s earnings per share goal.
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The Company’s 2007 results compared to its targets for some of these key indicators are reflected in the following chart:
See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The financial performance achieved in 2007 reflects the continued emphasis that management places on these indicators, as well as the commitment shown by employees in achieving or exceeding management’s expectations.
Earnings
The Company’s 2007 net income after dividends on preferred and preference stock totaled $836 million representing a $48.9 million, or 6.2%, increase over 2006. Operating income increased slightly in 2007 primarily due to increased operating revenues from transmission and outdoor lighting and decreased property taxes. Net income increased primarily due to higher allowance for equity funds used during construction and lower income tax expenses resulting from the Company’s donation of Tallulah Gorge to the State of Georgia. This net income increase was partially offset by higher non-fuel operating expenses and increased financing costs. The Company’s 2006 earnings totaled $787 million representing a $42.9 million, or 5.8%, increase over 2005. Operating income increased in 2006 due to higher base retail revenues and wholesale non-fuel revenues, partially offset by higher non-fuel operating expenses. The Company’s 2005 earnings totaled $744 million representing a $61.6 million, or 9.0%, increase over 2004. Operating income increased in 2005 due to higher base retail revenues resulting from retail rate increases and favorable weather conditions, partially offset by an increase in non-fuel operating expenses.
RESULTS OF OPERATIONS
A condensed income statement for the Company follows:
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Operating Revenues
Operating revenues in 2007, 2006, and 2005, and the percent of change from the prior year were as follows:
Retail base revenues were $3.8 billion in 2007. There was not a material change in total retail base revenues compared to 2006, although industrial base revenues decreased $56.5 million, or 8.5%, primarily due to lower sales and a lower contribution from market-driven rates for large commercial and industrial customers. This decrease was partially offset by a $31.8 million, or 2.1%, increase in residential base revenues as well as a $22.6 million, or 1.5%, increase in commercial base revenues primarily due to higher sales from favorable weather and customer growth of 1.2%. Retail base revenues of $3.8 billion in 2006 increased $7 million, or 0.2%, from 2005 primarily due to customer growth of 1.9% and more favorable weather, partially offset by lower contributions from market-driven rates to large commercial and industrial customers. Retail base revenues of $3.8 billion in 2005 increased by $360 million, or 10.6%, from 2004 primarily due to the retail rate increases effective January 1, 2005 and June 1, 2005, sustained economic strength, customer growth, more favorable weather, and generally higher prices to large business customers.
Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power, and do not affect net income. See FUTURE EARNINGS POTENTIAL - “PSC Matters - Fuel Cost Recovery” herein for additional information.
Wholesale revenues from sales to non-affiliated utilities were:
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Revenues from unit power sales have remained relatively constant in all periods presented. Revenues from other non-affiliated sales decreased $9.6 million, or 2.0%, in 2007, and increased $21.0 million, or 4.6%, and $273.2 million, or 146.2%, in 2006 and 2005, respectively. The decrease in 2007 was primarily due to a decrease in revenues from large territorial contracts resulting from lower emissions allowance prices. The increase in 2006 was due to a 0.6% increase in the demand for kilowatt-hour (KWH) energy sales due to a new contract with an electrical membership corporation (EMC) that went into effect in April 2006. The increase in 2005 was primarily due to contracts with 30 EMCs that went into effect in January 2005 which increased the demand for energy.
Wholesale revenues from sales to affiliated companies within the Southern Company system will vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliated sales and purchases are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the Federal Energy Regulatory Commission (FERC). In 2007, KWH energy sales to affiliates decreased 5.0% while revenues from sales to affiliates increased 10.0%. This was primarily due to the increased cost of fuel and other marginal generation costs. In 2006 and 2005, KWH energy sales to affiliates increased 8.5% and 2.2%, respectively, due to higher demand. However, revenues from these sales decreased by 8.3% in 2006 due to reduced cost per KWH delivered while revenues from these sales increased 59.8% in 2005 due to higher fuel prices. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
Other operating revenues increased $22.2 million, or 9.4%, in 2007 primarily due to an $11.6 million increase in transmission revenues due to the increased usage of the Company’s transmission system by non-affiliated companies, a $7.9 million increase in revenues from outdoor lighting activities due to a 10% increase in the number of lighting customers, and a $4.0 million increase from customer fees. Other operating revenues increased $24.6 million, or 11.6%, in 2006 primarily due to increased revenues of $14.1 million related to work performed for the other owners of the integrated transmission system (ITS) in the State of Georgia, higher customer fees of $4.6 million, and higher outdoor lighting revenues of $6.1 million. Other operating revenues increased $26.1 million, or 14.1%, in 2005 primarily due to higher transmission revenues of $16 million related to work performed for the other owners of the ITS, higher revenues under the open access tariff agreement, higher outdoor lighting revenues of $5.4 million, and higher customer fees that went into effect in 2005 of $5.9 million.
Energy Sales
Changes in revenues are influenced heavily by the change in volume of energy sold from year to year. KWH sales for 2007 and the percent change by year follow:
Residential KWH sales increased 2.4% in 2007 over 2006 due to favorable weather and a 1.3% increase in residential customers. Commercial KWH sales increased 2.9% in 2007 over 2006 primarily due to favorable weather and a 0.3% increase in commercial customers. Industrial KWH sales decreased 0.3% primarily due to reduced demand and closures within the textile industry; however, this was partially offset by a 2.9% increase in the number of industrial customers.
Residential KWH sales increased 2.7% in 2006 over 2005 due to customer growth of 1.9% and more favorable weather. Commercial KWH sales increased 2.5% in 2006 over 2005 due to customer growth of 2.0% and a reclassification of customers from industrial to
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commercial to be consistent with the rate structure approved by the Georgia Public Service Commission (PSC). Industrial KWH sales decreased 1.0% due to a 3.4% decrease in the number of customers as a result of this reclassification.
Residential KWH sales increased 2.7% in 2005 over 2004 due to more favorable weather, customer growth of 1.8%, and a 0.9% increase in the average energy consumption per customer. Commercial KWH sales increased 6.0% in 2005 when compared to 2004 due to more favorable weather, sustained economic strength, customer growth of 1.9%, and a reclassification of customers from industrial to commercial to be consistent with the rate structure approved by the Georgia PSC. Industrial KWH sales decreased 5.0% primarily due to this reclassification of customers.
Fuel and Purchased Power Expenses
Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market. Details of the Company’s electricity generated and purchased were as follows:
Fuel and purchased power expenses were $3.7 billion in 2007, an increase of $312.9 million, or 9.3%, above prior year costs. This increase was driven by a $414.5 million increase in total energy costs due to the higher average cost of fuel and purchased power. This was partially offset by a $101.6 million reduction due to less KWHs purchased.
Fuel and purchased power expenses were $3.4 billion in 2006, an increase of $124.4 million, or 3.8%, above prior year costs. This increase was driven by a $146.1 million increase related to higher KWHs generated and purchased partially offset by a $21.7 million decrease in the average cost of fuel and purchased power.
Fuel and purchased power expenses were $3.3 billion in 2005, an increase of $863.4 million, or 36.1%, above prior year costs. This increase was the result of an $881.2 million increase in the average cost of fuel and purchased power partially offset by a $17.8 million decrease related to total lower KWHs generated and purchased.
In 2007, the Company entered into power purchase agreements (PPAs) with companies to purchase a total of approximately 1,795 megawatts (MW). These contracts start in 2010. These agreements have been approved by the Georgia PSC and the FERC, as required. Of the total capacity, approximately 561 MW will expire in 2017, 292 MW in 2025, and 942 MW in 2030. These contracts are expected to result in higher non-fuel expenses that will be subject to recovery through future base rates. Additionally, in December 2007 and January 2008, the Company entered into two biomass renewable generation contracts for 50 MW each. Both contracts begin in 2010 and one expires in 2025 and the other expires in 2030.
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In 2006, the Company entered into three PPAs to purchase a total of approximately 1,000 MW annually from June 2009 through May 2024. These agreements were approved by the Georgia PSC.
These agreements satisfy growth and replace expiring agreements. The agreements are expected to result in higher non-fuel expenses that will be subject to recovery through future base rates.
While there has been a significant upward trend in the cost of coal and natural gas since 2003, prices moderated somewhat in 2006 and 2007. Coal prices have been influenced by a worldwide increase in demand from developing countries, as well as increases in mining and fuel transportation costs. While demand for natural gas in the United States continued to increase in 2007, natural gas supplies have also risen due to increased production and higher storage levels. During 2007, uranium prices were volatile and increased over the course of the year due to increasing long-term demand, with primary production levels at approximately 55% to 60% of demand. Secondary supplies and inventories were sufficient to fill the primary production shortfall.
Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s fuel cost recovery provisions. See FUTURE EARNINGS POTENTIAL - “PSC MATTERS - Fuel Cost Recovery” for additional information.
Other Operations and Maintenance Expenses
In 2007, the total change in other operations and maintenance expenses was immaterial compared to 2006.
In 2006, other operations and maintenance expenses decreased $11.0 million, or 0.7%, from the prior year. Maintenance for generating plants decreased $20.0 million in 2006 as a result of fewer scheduled outages than 2005, offset by an increase of $18.2 million for transmission and distribution expenses related to load dispatching and overhead line maintenance. Also contributing to the decrease were lower employee benefit expenses related to medical benefits and lower workers compensation expense of $23.2 million, partially offset by lower pension income of $13.7 million.
In 2005, other operations and maintenance expenses increased $86 million, or 5.8%. Maintenance for generating plant and transmission and distribution increased $27.5 million and $15.9 million, respectively, as a result of scheduled outages and, to a lesser extent, certain flexible projects planned for other periods. Increased employee benefit expense of $18.9 million related to pension and medical benefits and higher property insurance costs of $4.6 million resulting from storm damage also contributed to the increase. Customer assistance expense and uncollectible account expense also increased an additional $9.3 million in 2005 over 2004, primarily as a result of promotional expenses related to an energy efficiency program and an increased number of customer bankruptcies.
Depreciation and Amortization
Depreciation and amortization increased $12.4 million, or 2.5%, in 2007 from the prior year primarily due to a 3.4% increase in plant in service from the prior year. This increase was partially offset by a decrease in amortization due to a regulatory liability related to the inclusion of certified PPAs in retail rates as ordered by the Georgia PSC under the terms of the retail rate plan for the three years ended December 31, 2007 (2004 Retail Rate Plan). Depreciation and amortization decreased $27.9 million, or 5.3%, in 2006 from the prior year due to the scheduled decrease in amortization related to this regulatory liability. This decrease was partially offset by a $15.9 million, or 3.2%, increase in depreciation expense in 2006 over 2005 due to an increase in plant in service. Depreciation and amortization increased $230 million, or 77.5%, in 2005 over 2004 primarily due to the expiration at the end of 2004 of certain accelerated amortization provisions of the previously existing retail rate plan. See Note 3 to the financial statements under “Retail Regulatory Matters - Rate Plans” for additional information.
Taxes Other than Income Taxes
Taxes other than income taxes decreased $7.7 million, or 2.6%, in 2007 primarily due to the resolution of a dispute regarding property taxes in Monroe County, Georgia. See Note 3 to the financial statements under “Property Tax Dispute” for additional information. Taxes other than income taxes increased $22.8 million, or 8.3%, in 2006 primarily due to higher property taxes of $13.3 million as a result of an increase in property values and higher municipal gross receipts taxes of $9.1 million as a result of increased retail operating revenues. Taxes other than income taxes increased $33 million, or 13.6%, in 2005 primarily due to higher municipal gross receipts taxes of $18.1 million resulting from increased retail operating revenues and higher property taxes of $14.0 million.
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Allowance for Equity Funds Used During Construction
Allowance for equity funds used during construction (AFUDC) increased $36.7 million, or 116.3%, in 2007 primarily due to the increase in the Company’s construction work in progress balance related to ongoing transmission, distribution, and environmental projects. AFUDC remained relatively constant in 2006 and 2005.
Interest Expense, Net of Amounts Capitalized
Interest expense increased $25.5 million, or 8.0%, in 2007 primarily due to a 13.9% increase in long-term debt levels due to the issuance of additional senior notes and pollution control bonds. Interest expense increased $22.5 million, or 7.6%, in 2006 primarily due to generally higher interest rates on variable rate debt and commercial paper, the issuance of additional senior notes, and higher average balances of short-term debt. Interest expense increased $40.6 million, or 15.9%, in 2005 primarily due to the issuance of additional senior notes and generally higher interest rates on variable rate debt and commercial paper.
Other Income and (Expense), Net
Other income and (expense), net increased $5.8 million, or 66.5%, in 2007 primarily due to $4.0 million from land and timber sales. Other income and (expense), net increased $1.9 million, or 26.7%, in 2006 primarily due to reduced expenses of $2.9 million and $5.0 million related to the employee stock ownership plan and charitable donations, respectively, and increased revenues of $3.6 million, $5.4 million, and $3.4 million related to a residential pricing program, customer contracting, and customer facilities charges, respectively. These increases were partially offset by net financial gains on gas hedges of $18.6 million in 2005. Other income and (expense), net increased $21.5 million in 2005 from 2004, or 148.0%, primarily due to $16.8 million of additional gas hedge gains.
Income Taxes
Income taxes decreased $24.8 million, or 5.6%, in 2007 primarily due to state and federal deductions for the Company’s donation of 2,200 acres in the Tallulah Gorge area to the State of Georgia and higher federal manufacturing deductions. In 2006, income taxes decreased $5.1 million, or 1.1%, primarily due to the recognition of state tax credits. In 2005, income taxes increased $53.5 million, or 13.6%, primarily due to higher pre-tax net income. See Note 5 to the financial statements for additional information.
Effects of Inflation
The Company is subject to rate regulation that is based on the recovery of historical costs. When historical costs are included, or when inflation exceeds projected costs used in rate regulation or market-based prices, the effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. In addition, income tax laws are based on historical costs. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations such as long-term debt, preferred securities, preferred stock, and preference stock. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed in the Company’s approved electric rates.
FUTURE EARNINGS POTENTIAL
General
The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the Georgia PSC under cost-based regulatory principles. Prices for electricity relating to PPAs, interconnecting transmission lines, and the exchange of electric power are set by the FERC. Retail rates and revenues are reviewed and adjusted periodically with certain limitations. See ACCOUNTING POLICIES - “Application of Critical Accounting Policies and Estimates - Electric Utility Regulation” herein and Note 3 to the financial statements under “Retail Regulatory Matters” and “FERC Matters” for additional information about regulatory matters.
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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 business of selling electricity. These factors include the ability of the Company to maintain a stable regulatory environment that continues to allow for the recovery of all prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the Company’s service area.
Environmental Matters
Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. Some of the factors driving the potential for such an increase are higher commodity costs, market demand for labor, and scope additions and clarifications. The timing, specific requirements, and estimated costs could also change as environmental statutes and regulations are adopted or modified. Under the 2007 Retail Rate Plan approved by the Georgia PSC on December 18, 2007, an environmental compliance cost recovery (ECCR) tariff was implemented on January 1, 2008 to allow for the recovery of most of the costs related to environmental controls mandated by state and federal regulation scheduled for completion in 2008, 2009, and 2010. See Note 3 to the financial statements under “Rate Plans” for additional information.
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and the Company, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities including the Company’s Plants Bowen and Scherer. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama after Alabama Power was dismissed from the original action. In these lawsuits, the EPA alleged that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and the Company. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The action against the Company has been administratively closed since the spring of 2001, and the case has not been reopened.
In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving the alleged NSR violations at Plant Miller. The consent decree required Alabama Power to pay $100,000 to resolve the government’s claim for a civil penalty and to donate $4.9 million of sulfur dioxide emission allowances to a nonprofit charitable organization and formalized specific emissions reductions to be accomplished by Alabama Power, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in Alabama granted Alabama Power’s motion for summary judgment and entered final judgment in favor of Alabama Power on the EPA’s claims related to the four remaining plants.
The plaintiffs appealed the district court’s decision to the U.S. Court of Appeals for the Eleventh Circuit, and the appeal was stayed by the Appeals Court pending the U.S. Supreme Court’s decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke Energy case in April 2007. On October 5, 2007, the U.S. District Court for the Northern District of Alabama issued an order in the Alabama Power case indicating a willingness to re-evaluate its previous decision in light of the Supreme Court’s Duke Energy opinion. On December 21, 2007, the Eleventh Circuit vacated the district court’s decision in the Alabama Power case and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court’s decision in the Duke Energy case.
The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in this matter could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
The EPA has issued a series of proposed and final revisions to its NSR regulations under the Clean Air Act, many of which have been subject to legal challenges by environmental groups and states. In June 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s revisions to NSR regulations that were issued in December 2002 but vacated portions of those
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revisions addressing the exclusion of certain pollution control projects. These regulatory revisions have been adopted by the State of Georgia. In March 2006, the U.S. Court of Appeals for the District of Columbia Circuit also vacated an EPA rule which sought to clarify the scope of the existing routine maintenance, repair, and replacement exclusion. The EPA has also published proposed rules clarifying the test for determining when an emissions increase subject to the NSR permitting requirements has occurred. The impact of these proposed rules will depend on adoption of the final rules by the EPA and the State of Georgia’s implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.
Carbon Dioxide Litigation
In July 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005, and no decision has been issued. The ultimate outcome of these matters cannot be determined at this time.
Environmental Statutes and Regulations
General
The Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; and the Endangered Species Act. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2007, the Company had invested approximately $2.4 billion in capital projects to comply with these requirements, with annual totals of $856 million, $351 million, and $117 million for 2007, 2006, and 2005, respectively. The Company expects that capital expenditures to assure compliance with existing and new statutes, and regulations will be an additional $707 million, $353 million, and $246 million for 2008, 2009, and 2010, respectively. The Company’s compliance strategy is impacted by changes to existing environmental laws, statutes and regulations, the cost, availability, and existing inventory of emission allowances, and the Company’s fuel mix. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY - “Capital Requirements and Contractual Obligations” herein.
Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company. New environmental legislation or regulations, or changes to existing statutes or regulations, could affect many areas of the Company’s operations; however, the full impact of any such changes cannot be determined at this time.
Air Quality
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2007, the Company had spent approximately $2.1 billion in reducing sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been announced and are currently being installed at several plants to further reduce SO2, NOx, and mercury emissions, maintain compliance with existing regulations, and meet new requirements.
In 2004, the EPA designated nonattainment areas under an eight-hour ozone standard. Areas within the Company’s service area that were designated as nonattainment under the eight-hour ozone standard include Macon and a 20-county area within metropolitan Atlanta. The Macon area was redesignated by the EPA as an attainment area on September 19, 2007. In December 2006, the
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U.S.Court of Appeals for the District of Columbia Circuit vacated the first set of implementation rules adopted in 2004 and remanded the rules to the EPA for further refinement. On June 20, 2007, the EPA proposed additional revisions to the current eight-hour ozone standard which, if enacted, could result in the designation of new nonattainment areas within the Company’s service territory. The EPA has requested comment and is expected to publish final revisions to the standard in 2008. The impact of this decision, if any, cannot be determined at this time and will depend on subsequent legal action and/or future nonattainment designations and state regulatory plans.
During 2005, the EPA’s fine particulate matter nonattainment designations became effective for several areas within the Company’s service area. State plans for addressing the nonattainment designations under the existing standard are required by April 2008 and could require further reductions in SO2 and NOx emissions from power plants. In September 2006, the EPA published a final rule which increased the stringency of the 24-hour average fine particulate matter air quality standard. In December 2007, state agencies recommended to the EPA that an area encompassing all or parts of 22 counties within metropolitan Atlanta be designated as nonattainment for this standard. The EPA plans to designate nonattainment areas based on the new standard by December 2009. The ultimate outcome of this matter depends on the development and submittal of the required state plans and the resolution of pending legal challenges and, therefore, cannot be determined at this time.
The EPA issued the final Clean Air Interstate Rule in March 2005. This cap-and-trade rule addresses power plant SO2 and NOx emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including the State of Georgia, are subject to the requirements of the rule. The rule calls for additional reductions of NOx and/or SO2 to be achieved in two phases, 2009/2010 and 2015. The State of Georgia has completed plans to implement this program. These reductions will be accomplished by the installation of additional emission controls at the Company’s coal-fired facilities and/or by the purchase of emission allowances from a cap-and-trade program. The State of Georgia implemented the Clean Air Interstate Rule, and in June 2007, approved a “multi-pollutant rule” that will require plant specific emission controls on all but the smallest generating units in Georgia according to a schedule set forth in the rule. The rule is designed to ensure reductions in emissions of SO2, NOx, and mercury in Georgia.
The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized in July 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves (1) the application of Best Available Retrofit Technology (BART) to certain sources built between 1962 and 1977 and (2) the application of any additional emissions reductions which may be deemed necessary for each designated area to achieve reasonable progress by 2018 toward the natural conditions goal. Thereafter, for each 10-year planning period, additional emissions reductions will be required to continue to demonstrate reasonable progress in each area during that period. For power plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for SO2 and NOx.
Extensive studies were performed for each of the Company’s affected units to demonstrate that additional particulate matter controls are not necessary under BART. At the request of the State of Georgia, additional analyses were performed for certain units in Georgia to demonstrate that no additional SO2 controls were required. States are currently completing implementation plans that contain strategies for BART and any other measures required to achieve the first phase of reasonable progress.
The impacts of the eight-hour ozone and the fine particulate matter nonattainment designations, and the Clean Air Visibility Rule on the Company will depend on the development and implementation of rules at the state level. Therefore, the full effects of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO2 and NOx emission controls within the next several years to assure continued compliance with applicable air quality requirements.
In March 2005, the EPA published the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emission allowance trading market. The final Clean Air Mercury Rule was challenged in the U.S. Court of Appeals for the District of Columbia Circuit. The petitioners alleged that the EPA was not authorized to establish a cap-and-trade program for mercury emissions and instead the EPA must establish maximum achievable control technology standards for coal-fired electric utility steam generating units. On February 8, 2008, the court issued its ruling and vacated the Clean Air Mercury Rule. The Company’s overall environmental compliance strategy relies primarily on a combination of SO2 and NOx controls to reduce mercury emissions. Any significant changes in the strategy will depend on the outcome of any appeals and/or future federal and state rulemakings. Future rulemakings could require emission reductions more stringent than required by the Clean Air Mercury Rule.
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Water Quality
In July 2004, the EPA published its final technology-based regulations under the Clean Water Act for the purpose of reducing impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures. The rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants. On January 25, 2007, the U.S. Court of Appeals for the Second Circuit overturned and remanded several provisions of the rule to the EPA for revisions. Among other things, the court rejected the EPA’s use of “cost-benefit” analysis and suggested some ways to incorporate cost considerations. The full impact of these regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by State of Georgia regulatory agencies and, therefore, cannot be determined at this time.
Environmental Remediation
The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and release of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under “Environmental Matters - Environmental Remediation” for additional information.
Global Climate Issues
Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions continue to be considered in Congress. The ultimate outcome of these proposals cannot be determined at this time; however, mandatory restrictions on the Company’s greenhouse gas emissions could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. The EPA is currently developing its response to this decision. Regulatory decisions that will follow from this response may have implications for both new and existing stationary sources, such as power plants. The ultimate outcome of these rulemaking activities cannot be determined at this time; however, as with the current legislative proposals, mandatory restrictions on the Company’s greenhouse gas emissions could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
In addition, some states are considering or have undertaken actions to regulate and reduce greenhouse gas emissions. For example, on July 13, 2007, the Governor of the State of Florida signed three executive orders addressing reduction of greenhouse gas emissions within the state, including statewide emission reduction targets beginning in 2017. Included in the orders is a directive to the Florida Secretary of Environmental Protection to develop rules adopting maximum allowable emissions levels of greenhouse gases for electric utilities, consistent with the statewide emission reduction targets, and a request to the Florida PSC to initiate rulemaking requiring utilities to produce at least 20% of their electricity from renewable sources. The impact of any similar state requirements on the Company will depend on the development, adoption, and implementation of state laws or rules governing greenhouse gas emissions, and the ultimate outcome cannot be determined at this time.
International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. Current efforts focus on a potential successor to the Kyoto Protocol for the post 2008 through 2012 timeframe. The outcome and impact of the international negotiations cannot be determined at this time.
The Company continues to evaluate its future energy and emission profiles and is participating in voluntary programs to reduce greenhouse gas emissions and to help develop and advance technology to reduce emissions.
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FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.
In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales by the Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level.
In late June and July 2007, hearings were held in this proceeding and the presiding administrative law judge issued an initial decision on November 9, 2007 regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the Company to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates, and could also result in refunds of up to $5.8 million, plus interest. The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter.
On June 21, 2007, the FERC issued its final rule regarding market-based rate authority. The FERC generally retained its current market-based rate standards. The impact of this order and its effect on the generation dominance proceeding cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies (including the Company), Southern Power, and Southern Company Services, Inc. (SCS), as agent, under the terms of which the power pool of Southern Company is operated, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct.
In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms and Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. Southern Company filed with the FERC in November 2006 a compliance plan in connection with the order. On April 19, 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan is not expected to have a material impact on the Company’s financial statements. On November 19, 2007, Southern Company notified the FERC that the plan had been implemented and the FERC division of audits subsequently began an audit pertaining to compliance implementation and related matters, which is ongoing.
Generation Interconnection Agreements
In November 2004, generator company subsidiaries of Tenaska, Inc. (Tenaska), as counterparties to three previously executed interconnection agreements with subsidiaries of Southern Company, including the Company, filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $7.9 million previously paid for interconnection facilities. No other similar complaints are pending with the FERC.
On January 19, 2007, the FERC issued an order granting Tenaska’s requested relief. Although the FERC’s order required the modification of Tenaska’s interconnection agreements, under the provisions of the order the Company determined that no refund was payable to Tenaska. Southern Company requested rehearing asserting that the FERC retroactively applied a new principle to existing interconnection agreements. Tenaska requested rehearing of the FERC’s methodology for determining the amount of refunds. The requested rehearings were denied and Southern Company and Tenaska have appealed the orders to the U.S. Circuit Court for the District of Columbia. The final outcome of this matter cannot now be determined.
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PSC Matters
Rate Plans
In December 2007, the Georgia PSC approved the 2007 Retail Rate Plan for the years 2008 through 2010. Under the 2007 Retail Rate Plan, the Company’s earnings will continue to be evaluated against a retail return on common equity (ROE) range of 10.25% to 12.25%. Two-thirds of any earnings above 12.25% will be applied to rate refunds with the remaining one-third applied to an ECCR tariff. The Company agreed that it will not file for a general base rate increase during this period unless its projected retail ROE falls below 10.25%. Retail base rates increased by approximately $99.7 million effective January 1, 2008 to provide for cost recovery of transmission, distribution, generation and other investments, as well as increased operating costs. In addition, the ECCR tariff was implemented to allow for the recovery of costs for required environmental projects mandated by state and federal regulations. The ECCR tariff increased rates by approximately $222 million effective January 1, 2008.
The Company is required to file a general rate case by July 1, 2010, in response to which the Georgia PSC would be expected to determine whether the 2007 Retail Rate Plan should be continued, modified, or discontinued. See Note 3 to the financial statements under “Retail Regulatory Matters - Rate Plans” for additional information.
Fuel Cost Recovery
The Company has established fuel cost recovery rates approved by the Georgia PSC. In March 2006, the Company and Savannah Electric filed a combined request for fuel cost recovery rate changes with the Georgia PSC to be effective July 1, 2006, concurrent with the merger of the companies. In June 2006, the Georgia PSC ruled on the request and approved an increase in the Company’s total annual billings of approximately $400 million. The Georgia PSC order provided for a combined ongoing fuel forecast but reduced the requested increase related to such forecast by $200 million. With respect to the merger, the Georgia PSC also set a Merger Transition Adjustment (MTA) applicable to customers in the former Savannah Electric service territory so that the fuel rate that became effective on July 1, 2006 plus the MTA equaled the applicable fuel rate paid by such customers as of June 30, 2006. Amounts collected under the MTA were credited to customers in the original Georgia Power service territory through a Merger Transition Credit (MTC) through December 31, 2007. The order also required the Company to file for a new fuel cost recovery rate on a semi-annual basis, beginning in September 2006. Accordingly, in September 2006, the Company filed a request to recover fuel costs incurred through August 2006 by increasing the fuel cost recovery rate. In November 2006, under agreement with the Georgia PSC staff, the Company filed a supplementary request reflecting a forecast of annual fuel costs, as well as updated information for previously incurred fuel costs.
On February 6, 2007, the Georgia PSC approved an increase in the Company’s total annual billings of approximately $383 million effective March 1, 2007. The order reduced the Company’s requested increase in the forecast of annual fuel costs by $40 million and disallowed $4 million of previously incurred fuel costs. Estimated under recovered fuel costs through February 2007 are to be recovered through May 2009 for customers in the original Georgia Power territory and through November 2009 for customers in the former Savannah Electric territory. The order also requires the Company to file for a new fuel cost recovery rate no later than March 1, 2008. As of December 31, 2007, the Company had a total under recovered fuel cost balance of approximately $692 million, of which approximately $106 million is not included in current rates.
Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, a change in the billing factor has no significant effect on the Company’s revenues or net income, but does impact annual cash flow. In accordance with Georgia PSC order, approximately $307 million of the under recovered regulatory clause revenues for the Company is included in deferred charges and other assets at December 31, 2007. See Note 1 to the financial statements under “Revenues” and Note 3 to the financial statements under “Retail Regulatory Matters” for additional information.
Income Tax Matters
Georgia State Income Tax Credits
The Company’s 2005 through 2007 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. The Company has also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue (DOR) has not responded to these claims. On July 24, 2007, the Company filed a complaint in the Superior Court of Fulton
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County to recover the credits claimed for the years 2002 through 2004. If allowed, these claims could have a significant, possibly material, positive effect on the Company’s net income. If the Company is not successful, payment of the related state tax could have a significant, possibly material, negative effect on the Company’s cash flow. The ultimate outcome of this matter cannot now be determined. See Note 3 under “Income Tax Matters” and Note 5 under “Unrecognized Tax Benefits” for additional information.
Internal Revenue Code Section 199 Domestic Production Deduction
The American Jobs Creation Act of 2004 created a tax deduction for the portion of income attributable to U.S. production activities as defined in the Internal Revenue Code of 1986, as amended (Internal Revenue Code), Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for years 2007 through 2009, and a 9% rate applicable for all years after 2009. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.
Bonus Depreciation
On February 13, 2008, President Bush signed the Economic Stimulus Act of 2008 (Stimulus Act) into law. The Stimulus Act includes a provision that allows 50% bonus depreciation for certain property acquired in 2008 and placed in service in 2008, or in limited circumstances, 2009. The Company is currently assessing the financial implications of the Stimulus Act; however, the ultimate impact cannot be determined at this time.
Nuclear
Nuclear Projects
In August 2006, as part of a potential expansion of Plant Vogtle, the Company and Southern Nuclear Operating Company, Inc. (SNC) filed an application with the Nuclear Regulatory Commission (NRC) for an early site permit (ESP) on behalf of the owners of Plant Vogtle. In addition, the Company and SNC notified the NRC of their intent to apply for a combined construction and operating license (COL) in 2008. Ownership agreements have been signed with each of the existing Plant Vogtle co-owners. See Note 4 to the financial statements for additional information on these co-owners. In June 2006, the Georgia PSC approved the Company’s request to establish an accounting order that would allow the Company to defer for future recovery the ESP and COL costs, of which the Company’s portion is estimated to total approximately $51 million. At December 31, 2007, approximately $28.4 million is included in deferred charges and other assets. At this point, no final decision has been made regarding actual construction. Any new generation resource must be certified by the Georgia PSC in a separate proceeding.
Nuclear Relicensing
In January 2002, the NRC granted the Company a 20-year extension of the licenses for both units at Plant Hatch which permits the operation of Units 1 and 2 until 2034 and 2038, respectively. The Company filed an application with the NRC in June 2007 to extend the licenses for Plant Vogtle Units 1 and 2 for an additional 20 years. The Company anticipates the NRC may make a decision regarding the license extension for Plant Vogtle as early as 2009.
Other Matters
The Company is involved in various other matters being litigated, regulatory matters, and certain tax-related issues 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. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements. See Note 3 to the financial statements for information regarding material issues.
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ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed 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 Georgia PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies Financial Accounting Standards Board (FASB) Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), which requires the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of SFAS No. 71 has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on the Company’s results of operations 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 liabilities based on applicable regulatory guidelines and accounting principles generally accepted in the United States. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s financial statements.
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a loss is considered probable and reasonably estimable in accordance with generally accepted accounting principles. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company’s financial statements. These events or conditions include the following:
•
Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances, hazardous and solid wastes, and other environmental matters.
•
Changes in existing income tax regulations or changes in Internal Revenue Service (IRS) or Georgia DOR interpretations of existing regulations.
•
Identification of additional sites that require environmental remediation or the filing of other complaints in which the Company may be asserted to be a potentially responsible party.
•
Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant.
•
Resolution or progression of existing matters through the legislative process, the court systems, the IRS, the FERC, or the EPA.
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Unbilled Revenues
Revenues related to the sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, and power delivery volume and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company’s results of operations.
New Accounting Standards
Income Taxes
On January 1, 2007, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), which requires companies to determine whether it is “more likely than not” that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. It also provides guidance on the recognition, measurement, and classification of income tax uncertainties, along with any related interest and penalties. The provisions of FIN 48 were applied to all tax positions beginning January 1, 2007. The adoption of FIN 48 did not have a material impact on the Company’s financial statements. See Note 5 under “Unrecognized Tax Benefits” for additional information.
Pensions and Other Postretirement Plans
On December 31, 2006, the Company adopted FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS No. 158), which requires recognition of the funded status of its defined benefit postretirement plans in the balance sheets. Additionally, SFAS No. 158 will require the Company to change the measurement date for its defined benefit postretirement plan assets and obligations from September 30 to December 31 beginning with the year ending December 31, 2008. See Note 2 to the financial statements for additional information.
Fair Value Measurement
The FASB issued FASB Statement No. 157, “Fair Value Measurements” (SFAS No. 157) in September 2006. SFAS No. 157 provides guidance on how to measure fair value where it is permitted or required under other accounting pronouncements. SFAS No. 157 also requires additional disclosures about fair value measurements. The Company adopted SFAS No. 157 in its entirety on January 1, 2008, with no material effect on its financial condition or results of operations.
Fair Value Option
In February 2007, the FASB issued FASB Statement No. 159, “Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115” (SFAS No. 159). This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. The Company adopted SFAS No. 159 on January 1, 2008, with no material effect on its financial condition or results of operations.
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company’s financial condition remained stable at December 31, 2007. Cash flow from operations totaled $1.4 billion, an increase of $248.5 million from 2006, primarily due to higher retail revenues primarily related to higher fuel cost recovery revenues and less cash used for working capital primarily from lower inventory additions and increases in other current liabilities. Cash flow from operations increased $117.4 million in 2006, primarily from increased retail operating revenues partially offset by higher fuel inventories and an increase in under recovered deferred fuel costs. In 2005, cash flow from operations increased $58.4 million primarily from increased retail operating revenues, partially offset by the increase in under recovered deferred fuel costs.
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Net cash used for investing activities totaled $1.9 billion due to gross property additions primarily related to installation of equipment to comply with environmental standards, construction of transmission and distribution facilities, and purchase of nuclear fuel. The majority of funds needed for gross property additions for the last several years have been provided from operating activities, capital contributions from Southern Company, and the issuance of long and short-term debt and preference stock.
Cash provided from financing activities totaled $429.7 million primarily related to the issuance of new senior notes. The statements of cash flows provide additional details. See “Financing Activities” herein.
Significant balance sheet changes in 2007 include a $726 million increase in long-term debt and a $221 million increase in Preferred and Preference Stock primarily to replace short-term debt and provide funds for the Company’s continuous construction programs. Other balance sheet changes include an increase in total property, plant and equipment of $1.3 billion and a $206 million decrease in the under recovered fuel balance.
The Company’s ratio of common equity to total capitalization - including short-term debt - was 47.5% in 2007, 48.6% in 2006, and 47.9% in 2005. The Company has received investment grade ratings from the major rating agencies with respect to debt, preferred securities, preferred stock, and preference stock.
Sources of Capital
The Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows. However, the type and timing of any future financings, if needed, will depend on market conditions, regulatory approvals, and other factors. The issuance of long-term securities by the Company is subject to the approval of the Georgia PSC. In addition, the issuance of short-term debt securities by the Company is subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933, as amended. The amounts of securities authorized by the Georgia PSC and the FERC are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.
The Company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company.
The Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source for under recovered fuel costs and to meet cash needs which can fluctuate significantly due to the seasonality of the business.
To meet short-term cash needs and contingencies, at the beginning of 2008 the Company had credit arrangements with banks totaling $1.2 billion, of which $8 million was used to support an outstanding letter of credit. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.
At the beginning of 2008, bank credit arrangements were as follows:
The credit arrangement that expires in 2008 allows for the execution of term loans for an additional two-year period.
The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other traditional operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from issuances for the benefits of any other operating company. The obligations of each company under these arrangements are several; there is no cross affiliate credit support. As of December 31, 2007, the Company had $616 million of outstanding commercial paper and a $100 million short-term bank loan outstanding.
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Financing Activities
During 2007, the Company issued $1.5 billion of senior notes and $225 million of preference stock and incurred $191 million of obligations related to the issuance of pollution control bonds. The issuances were used to reduce the Company’s short-term indebtedness, fund senior note maturities totaling $300 million, redeem $763 million of long-term debt payable to affiliated trusts, and fund the Company’s ongoing construction program.
Credit Rating Risk
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- or Baa3 or below. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. These contracts are primarily for physical electricity purchases and sales. At December 31, 2007, the maximum potential collateral requirements at a BBB- or Baa3 rating were approximately $9 million. The maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $515 million.
The Company is also party to certain agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade for the Company and/or Alabama Power. These agreements are primarily for natural gas and power price risk management activities. At December 31, 2007, the Company’s total exposure related to these types of agreements was approximately $15 million.
Market Price Risk
Due to cost-based rate regulation, the Company has limited exposure to market rate volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and hedging 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 tests, and sensitivity analysis.
To mitigate future exposure to changes in interest rates, the Company enters into forward starting interest rate swaps and other derivatives that have been designated as hedges. These derivatives have a notional amount of $539 million and are related to anticipated debt issuances over the next two years. The weighted average interest rate on $1.4 billion of outstanding variable long-term debt that has not been hedged at January 1, 2008 was 4.5%. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $14.2 million at January 1, 2008. Subsequent to December 31, 2007, the Company converted $115 million of floating rate pollution control bonds to a fixed rate mode. Additionally, the Company entered into floating to fixed interest rate swaps on $601 million of variable rate long-term debt. These actions reduced the Company’s exposure to variable rate debt to $704 million for the remainder of the year. Subsequent to these actions, a 100 basis point change in interest rates for all unhedged variable rate long-term debt would affect annualized interest expense by $7.7 million. See Notes 1 and 6 to the financial statements under “Financial Instruments” for additional information.
The Company’s $704 million of variable interest rate exposure relates to tax-exempt auction rate pollution control bonds. Recent weakness in the auction markets has resulted in higher interest rates. The Company has sent notice of conversion of $662 million of these auction rate securities to alternative interest rate determination methods and plans to remarket all remaining auction rate securities in a timely manner. None of the securities are insured or backed by letters of credit that would require approval of a guarantor or security provider. It is not expected that the higher rates as a result of the weakness in the auction markets will be material.
To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts for gas purchases.
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The Company has implemented a fuel hedging program at the instruction of the Georgia PSC. The changes in fair value of energy-related derivative contracts and year-end valuations were as follows at December 31:
(a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
Unrealized gains and losses from mark to market adjustments on derivative contracts related to the Company’s fuel hedging programs are recorded as regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are recovered through the Company’s fuel cost recovery mechanism. The Company realized net losses in 2007 and 2006 of $68 million and $66 million, respectively. Through June 30, 2006, the Company was allowed to retain 25% of net financial gains in earnings, and in 2005 the Company had a total net gain of $74.6 million of which the Company retained $18.6 million. See Note 3 to the financial statements under “Retail Regulatory Matters - Fuel Hedging Program” for additional information. Gains and losses on derivative contracts that are not designated as hedges are recognized in the statements of income as incurred. At December 31, 2007, the fair value gains (losses) of energy-related derivative contracts were reflected in the financial statements as follows:
Unrealized gains (losses) recognized in income were not material for any year presented. The Company is exposed to market price risk in the event of nonperformance by counterparties to the derivative energy contracts. The Company’s policy is to enter into agreements with counterparties that have investment grade credit ratings by Moody’s and Standard & Poor’s or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”
Capital Requirements and Contractual Obligations
The construction program of the Company is currently estimated to be $2.0 billion for 2008, $2.0 billion for 2009, and $1.8 billion for 2010. Environmental expenditures included in these estimated amounts are $707 million, $353 million, and $246 million for 2008, 2009, and 2010, respectively. Actual construction costs may vary from these estimates because of changes in such factors as: business
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conditions; environmental statutes and regulations; nuclear plant regulations; FERC rules and regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
As a result of requirements by the NRC, the Company has established external trust funds for nuclear decommissioning costs. 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 Georgia PSC and the FERC.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt and preferred securities and the related interest, preferred and preference stock dividends, leases, derivative obligations, and other purchase commitments are as follows. See Notes 1, 6, and 7 to the financial statements for additional information.
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Contractual Obligations
(a)
All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2008, 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 does not mature; therefore, amounts provided are for the next five years only.
(c)
For additional information see Notes 1 and 6 to the financial statements.
(d)
The timing related to the realization of $96 million in unrecognized tax benefits and interest payments cannot be reasonably and reliably estimated due to uncertainties in the timing of the effective settlement of tax positions. Of this $96 million, $71 million is the estimated cash payment. See Note 3 and Note 5 to the financial statements for additional information.
(e)
The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for the last three years were $1.6 billion, $1.6 billion, and $1.6 billion, respectively.
(f)
The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures, excluding those amounts related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services. At December 31, 2007, significant purchase commitments were outstanding in connection with the construction program.
(g)
As part of the Company’s program to reduce sulfur dioxide emissions from certain of its coal plants, the Company is constructing certain equipment and has entered into various long-term commitments for the procurement of limestone to be used in such equipment.
(h)
Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2007.
(i)
Long-term service agreements include price escalation based on inflation indices.
(j)
Projections of nuclear decommissioning trust contributions are based on the 2007 Retail Rate Plan.
(k)
The Company forecasts postretirement trust contributions over a three-year period. No contributions related to the Company’s pension trust are currently expected during this period. See Note 2 to the financial statements for additional information related to the pension and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2007 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company’s 2007 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail rates, fuel cost recovery, environmental regulations and expenditures, the Company’s projections for postretirement benefit trust contributions, financing activities, access to sources of capital, the impacts of the adoption of new accounting rules, completion of construction projects, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
•
the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, or particulate matter and other substances, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
•
current and future litigation, regulatory investigations, proceedings, or inquiries, including FERC matters and the pending EPA civil action against the Company;
•
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
•
variations in demand for electricity, including those relating to weather, the general economy, population, business growth (and declines), and the effects of energy conservation measures;
•
available sources and costs of fuel;
•
effects of inflation;
•
ability to control costs;
•
investment performance of the Company’s employee benefit plans;
•
advances in technology;
•
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate cases related to fuel cost recovery;
•
internal restructuring or other restructuring options that may be pursued;
•
potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;
•
the ability of counterparties of the Company to make payments as and when due;
•
the ability to obtain new short- and long-term contracts with neighboring utilities;
•
the direct or indirect effect on the Company’s business resulting from terrorist incidents and the threat of terrorist incidents;
•
interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company’s credit ratings;
•
the ability of the Company to obtain additional generating capacity at competitive prices;
•
catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as an avian influenza, or other similar occurrences;
•
the direct or indirect effects on the Company’s business resulting from incidents similar to the August 2003 power outage in the Northeast;
•
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
•
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
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STATEMENTS OF INCOME
For the Years Ended December 31, 2007, 2006, and 2005
Georgia Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2007, 2006, and 2005
Georgia Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2007 and 2006
Georgia Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2007 and 2006
Georgia Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF CAPITALIZATION
At December 31, 2007 and 2006
Georgia Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2007, 2006, and 2005
Georgia Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2007, 2006, and 2005
Georgia Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 2007 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Georgia Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies - Alabama Power, the Company, Gulf Power, and Mississippi Power - provide electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Southern Power constructs, acquires, and manages generation assets and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications services to the traditional operating companies and also markets these services to the public, and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy-related businesses. The investments in synthetic fuels ended on December 31, 2007. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants.
The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable interest entities where the Company is not the primary beneficiary.
The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC) and the Georgia Public Service Commission (PSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from those estimates.
Reclassifications
Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no effect on total assets, net income, or cash flows.
The balance sheets and the statements of cash flows have been modified to combine “Long-term Debt Payable to Affiliate Trusts” with “Long-term Debt.” Correspondingly, the statements of income were modified to report “Interest expense to affiliate trusts” together with “Interest expense, net of amounts capitalized”. The balance sheets were also modified to show a separate line item for “Prepaid Income Taxes”, the amount of which was included in “Prepaid Expenses” in the previous year’s presentation. Due to immateriality, the statements of cash flows were also modified by combining “Deferred expenses-affiliates” with “Other, net” within the operating activities section.
Affiliate Transactions
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, purchasing, accounting and statistical analysis, finance and treasury, tax, information resources, marketing, auditing, insurance and pension administration, human resources, systems and procedures, and other services with respect to business and operations and power pool operations. Costs for these services amounted to $442 million in 2007, $386 million in 2006, and $348 million in 2005. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.
The Company has an agreement with Southern Nuclear under which 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 $380 million in 2007, $348 million in 2006, and $328 million in 2005.
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NOTES (continued)
Georgia Power Company 2007 Annual Report
The Company had an agreement with Southern Power under which the Company operated and maintained Southern Power’s Plants Dahlberg, Franklin, and Wansley at cost. On August 1, 2007, that agreement was terminated and replaced with a service agreement under which the Company provides to Southern Power labor and other specifically requested services. Billings under these agreements with Southern Power amounted to $6.8 million in 2007, $5.4 million in 2006, and $5.2 million in 2005.
The Company has an agreement with SouthernLINC Wireless under which the Company receives digital wireless communications services and purchases digital equipment. Costs for these services amounted to $7.0 million in 2007, $7.1 million in 2006, and $7.7 million in 2005.
Southern Company’s 30% ownership interest in Alabama Fuel Products, LLC (AFP), which produced synthetic fuel, was terminated July 1, 2006. The Company had an agreement with an indirect subsidiary of Southern Company that provided services for AFP. Under this agreement, the Company provided certain accounting functions, including processing and paying fuel transportation invoices, and the Company was reimbursed for its expenses. Amounts billed under this agreement totaled approximately $85 million in 2007, $76 million in 2006, and $61 million in 2005. In addition, the Company purchased synthetic fuel from AFP for use at Plant Branch. Synthetic fuel purchases totaled $179 million, $195 million, and $216 million in 2007, 2006, and 2005, respectively. The synthetic fuel purchases and related party transactions were terminated as of December 31, 2007.
The Company has entered into several power purchase agreements (PPAs) with Southern Power for capacity and energy. Expenses associated with these PPAs were $440 million, $407 million, and $469 million in 2007, 2006, and 2005, respectively. Additionally, the Company had $26 million and $28 million of prepaid capacity expenses included in deferred charges and other assets in the balance sheets at December 31, 2007, and 2006, respectively. See Note 7 under “Purchased Power Commitments” for additional information.
The Company has an agreement with Gulf Power under which Gulf Power jointly owns a portion of Plant Scherer. Under this agreement, the Company operates Plant Scherer, and Gulf Power reimburses the Company for its proportionate share of the related expenses which were $5.1 million in 2007, $8.0 million in 2006, and $4.3 million in 2005. See Note 4 for additional information.
In 2007, the Company sold equipment at cost to Gulf Power for $4.0 million.
The Company provides incidental services to other Southern Company subsidiaries which are generally minor in duration and amount. However, with the hurricane damage experienced by Alabama Power, Gulf Power, and Mississippi Power in 2005, assistance provided to aid in storm restoration, including company labor, contract labor, and materials, caused an increase in these activities. The total amount of storm assistance provided to Alabama Power, Gulf Power, and Mississippi Power in 2005 was $4.3 million, $5.0 million, and $55.2 million, respectively. These activities were billed at cost. The Company provided no significant storm assistance to an affiliate in 2007 and 2006.
Also see Note 4 for information regarding the Company’s ownership in and PPA with Southern Electric Generating Company (SEGCO) and Note 5 for information on certain deferred tax liabilities due to affiliates.
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 Commitments” for additional information.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
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NOTES (continued)
Georgia Power Company 2007 Annual Report
Regulatory assets and (liabilities) reflected in the Company’s balance sheets at December 31 relate to the following:
Note:
The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
(a)
Asset retirement and removal liabilities are recorded, deferred income tax assets are recovered, and deferred tax liabilities are amortized over the related property lives, which may range up to 60 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.
(b)
Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue which may range up to 50 years.
(c)
Recorded as earned by employees and recovered as paid, generally within one year.
(d)
Recorded and recovered or amortized as approved by the Georgia PSC.
(e)
See “Property, Plant, and Equipment” herein.
(f)
Recovered and amortized over the average remaining service period which may range up to 16 years. See Note 2 under “Retirement Benefits.”
(g)
Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed 42 months. Upon final settlement, costs are recovered through the fuel cost recovery clause.
In the event that a portion of the Company’s operations is no longer subject to the provisions of SFAS No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair value. All regulatory assets and liabilities are reflected in rates.
Revenues
Energy and other revenues are recognized as services are provided. Unbilled revenues are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs and the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between the actual recoverable costs and amounts billed in current regulated rates.
Retail fuel cost recovery rates require periodic filings with the Georgia PSC. The Company is required to file its next fuel case by March 1, 2008. See Note 3 under “Retail Regulatory Matters - Fuel Cost Recovery.”
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NOTES (continued)
Georgia Power Company 2007 Annual Report
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 includes the cost of purchased emission allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel.
Nuclear Fuel Disposal Costs
The Company has contracts with the United States, acting through the U.S. Department of Energy (DOE), that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contracts, and the Company is pursuing legal remedies against the government for breach of contract.
On July 9, 2007, the U.S. Court of Federal Claims awarded the Company $30 million, based on its ownership interests, representing all of the direct costs of the expansion of spent nuclear fuel storage facilities from 1998 through 2004. On July 24, 2007, the government filed a motion for reconsideration, which was denied on November 1, 2007. The government filed an appeal on January 2, 2008. No amounts have been recognized in the financial statements as of December 31, 2007. The final outcome of this matter cannot be determined at this time, but no material impact on net income is expected as any award received is expected to be returned to customers.
Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into 2014. Construction of an on-site dry storage facility at Plant Vogtle is expected to begin in sufficient time to maintain pool full-core discharge capability. At Plant Hatch, an on-site dry storage facility is operational and can be expanded to accommodate spent fuel through the expected life of the plant.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost, less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll- related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction.
The Company’s property, plant, and equipment consisted of the following at December 31:
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred or performed with the exception of certain generating plant maintenance costs. As mandated by a Georgia PSC order, the Company defers and amortizes nuclear refueling costs over the unit’s operating cycle before the next refueling. The refueling cycles are 18 and 24 months for Plants Vogtle and Hatch,
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NOTES (continued)
Georgia Power Company 2007 Annual Report
respectively. Also, in accordance with the Georgia PSC order, the Company defers the costs of certain significant inspection costs for the combustion turbines at Plant McIntosh and amortizes such costs over 10 years, which approximates the expected maintenance cycle.
Income and Other Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. In accordance with FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), the Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information on the effect of adopting FIN 48.
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.6% in each of 2007, 2006, and 2005. Depreciation studies are conducted periodically to update the composite rates that are approved by the Georgia PSC. Effective January 1, 2008, the Company’s depreciation rates were revised by the Georgia PSC.
When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.
Under the Company’s retail rate plan for the three years ended December 31, 2007 (2004 Retail Rate Plan), the Company was ordered to recognize Georgia PSC-certified capacity costs in rates evenly over the three years covered by the 2004 Retail Rate Plan. The Company recorded credits to amortization of $19 million and $14 million in 2007 and 2006, respectively, and an increase to amortization of $33 million in 2005. See Note 3 under “Retail Regulatory Matters - Rate Plans” for additional information.
Asset Retirement Obligations and Other Costs of Removal
Asset retirement obligations are computed as the present value of the ultimate costs for an asset’s future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. The Company has received accounting guidance from the Georgia PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations will continue to be reflected in the balance sheets as a regulatory liability.
The liability recognized to retire long-lived assets primarily relates to the Company’s nuclear facilities, which include the Company’s ownership interests in Plants Hatch and Vogtle. The fair value of assets legally restricted for settling retirement obligations related to nuclear facilities as of December 31, 2007 was $589 million. In addition, the Company has retirement obligations related to various landfill sites, ash ponds, underground storage tanks, and asbestos removal. The Company also has identified retirement obligations related to certain transmission and distribution facilities, leasehold improvements, equipment on customer property, and property associated with the Company’s rail lines. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue to recognize in the statements of income the allowed removal costs in accordance with its regulatory treatment. Any difference between costs recognized under FASB Statement No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143) and FASB Interpretation No. 47, “Conditional Asset Retirement Obligations” and those reflected in rates are recognized as either a regulatory asset or liability in the balance sheets as ordered by the Georgia PSC. See “Nuclear Decommissioning” herein for further information on amounts included in rates.
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NOTES (continued)
Georgia Power Company 2007 Annual Report
Details of the asset retirement obligations included in the balance sheets are as follows:
Nuclear Decommissioning
The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The Company has external trust funds to comply with the NRC’s regulations. Use of the funds is restricted to nuclear decommissioning activities and the funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the Georgia PSC, as well as the Internal Revenue Service (IRS). The trust funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are classified as available-for-sale.
The trust funds are included in the balance sheets at fair value, as obtained from quoted market prices for the same or similar investments. As the external trust funds are actively managed by unrelated parties with limited direction from the Company, the Company does not have the ability to choose to hold securities with unrealized losses until recovery. Through 2005, the Company considered other-than-temporary impairments to be immaterial. However, since the January 1, 2006 effective date of FASB Staff Position FAS 115-1/124-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (FSP No. 115-1), the Company considers all unrealized losses to represent other-than-temporary impairments. The adoption of FSP No. 115-1 had no impact on the results of operations, cash flows, or financial condition of the Company as all losses have been and continue to be recorded through a regulatory liability, whether realized, unrealized, or identified as other-than-temporary.
Details of the securities held in these trusts at December 31, 2007 were as follows:
The contractual maturities of debt securities at December 31, 2007 were as follows: $2.6 million in 2008, $38.5 million in 2009-2012, $41.1 million in 2013-2017, and $85.4 million thereafter.
Sales of the securities held in the trust funds resulted in cash proceeds of $441.4 million, $457.4 million, and $372.5 million in 2007, 2006, and 2005, respectively, all of which were re-invested. Realized gains and other-than-temporary impairment losses were $43.7 million and $39.1 million, respectively, in 2007 and $17.8 million and $12.1 million, respectively, in 2006. Net realized gains/(losses) were $12.6 million in 2005. Realized gains and other-than-temporary impairment losses are determined on a specific
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NOTES (continued)
Georgia Power Company 2007 Annual Report
identification basis. In accordance with regulatory guidance, all realized and unrealized gains and losses are included in the regulatory liability for asset retirement obligations in the balance sheets and are not included in net income or other comprehensive income. Unrealized gains and other-than-temporary impairment losses are considered non-cash transactions for purposes of the statements of cash flows. Unrealized losses were not material in any period presented and did not require the recognition of any impairment to the underlying investments.
Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the Georgia 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 plans with the NRC designed to ensure that, over time, the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC.
Site study cost is the estimate to decommission a specific facility as of the site study year. The estimated costs of decommissioning are based on the most current study performed in 2006. The site study costs and accumulated provisions for decommissioning as of December 31, 2007 based on the Company’s ownership interests were as follows:
The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these 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 NRC generic estimate to decommission the radioactive portion of the facilities. The Georgia PSC approved annual decommissioning costs for ratemaking were $7 million annually for Plant Vogtle for 2005 through 2007. Under the 2007 Retail Rate Plan, the annual decommissioning cost for ratemaking will decrease to $3 million for Plant Vogtle. Based on current estimates, the Company projects the external trust funds for Plant Hatch will be adequate to meet the decommissioning obligations with no further contributions. The NRC estimates are $450 million and $313 million for Plants Hatch and Vogtle, respectively. Significant assumptions used to determine the costs for ratemaking include an estimated inflation rate of 2.9% and an estimated trust earnings rate of 4.9%. Another significant assumption was that the operating licenses for Plant Vogtle, would remain at 40 years until a 20-year extension requested by the Company in June 2007 is authorized by the NRC. The Company anticipates the NRC may make a decision regarding the license extension for Plant Vogtle as early as 2009.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized
In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. The equity component of AFUDC is not included in calculating taxable income. For the years 2007, 2006, and 2005, the average AFUDC rates were 8.4%, 8.3%, and 8.0%, respectively, and AFUDC capitalized was $96.8 million, $44.1 million, and $41.1 million, respectively. AFUDC and interest capitalized, net of taxes were 10.3%, 5.0%, and 4.9% of net income after dividends on preferred and preference stock for 2007, 2006, and 2005, respectively.
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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.
Storm Damage Reserve
The Company maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property as mandated by the Georgia PSC. Under the 2004 Retail Rate Plan, the Company accrued $6.6 million annually that was recoverable through base rates. Starting January 1, 2008, the Company will accrue $21.4 million annually under the 2007 Retail Rate Plan. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for storm damage costs.
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 costs of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
Fuel Inventory
Fuel inventory includes the average costs of oil, coal, natural gas, and emission allowances. Fuel is charged to inventory when purchased and then expensed as used and recovered by the Company through fuel cost recovery rates approved by the Georgia PSC. Emission allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.
Stock Options
Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. Prior to January 1, 2006, the Company accounted for options granted in accordance with Accounting Principles Board Opinion No. 25; thus, no compensation expense was recognized because the exercise price of all options granted equaled the fair market value on the date of the grant.
Effective January 1, 2006, the Company adopted the fair value recognition provisions of FASB Statement No. 123(R), “Share-Based Payment” (SFAS No. 123(R)), using the modified prospective method. Under that method, compensation cost for the years-ended December 31, 2007 and 2006 was recognized as the requisite service was rendered and included: (a) compensation cost for the portion of share-based awards granted prior to and that were outstanding as of January 1, 2006, for which the requisite service had not been rendered, based on the grant-date fair value of those awards as calculated in accordance with the original provisions of FASB Statement No. 123, “Accounting for Stock-Based Compensation”, and (b) compensation cost for all share-based awards granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123(R). Results for prior periods have not been restated.
The compensation cost and tax benefits related to the grant and exercise of Southern Company stock options to the Company’s employees are recognized in the Company’s financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company.
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For the Company, the adoption of SFAS No. 123(R) resulted in a reduction in earnings before income taxes and net income of $6.0 million and $3.7 million, respectively, for the year ended December 31, 2007, and $5.8 million and $3.6 million, respectively, for the year ended December 31, 2006. Additionally, SFAS No. 123(R) requires the gross excess tax benefits from stock option exercises to be reclassified as a financing cash flow as opposed to an operating cash flow; the reduction in operating cash flows and the increase in financing cash flows for the years ended December 31, 2007 and December 31, 2006 was $4.7 million and $2.8 million, respectively.
For the year ended December 31, 2005, prior to the adoption of SFAS No. 123(R), the pro forma impact on net income of fair-value accounting for options granted was as follows:
Because historical forfeitures have been insignificant and are expected to remain insignificant, no forfeitures were assumed in the calculation of compensation expense; rather they are recognized when they occur.
The estimated fair values of stock options granted in 2007, 2006, and 2005 were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company’s stock over a period equal to the expected term. The Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted:
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities and are measured at fair value. Substantially all of the Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are exempt from fair value accounting requirements and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the Georgia PSC-approved fuel hedging program. This results in the deferral of related gains and losses in other comprehensive income or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income.
The Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk.
The Company’s financial instruments for which the carrying amount did not equal fair value at December 31 were as follows:
The fair values were based on either closing market prices or closing prices of comparable instruments.
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Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, and prior to the adoption of SFAS No.158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS No. 158) the minimum pension liability, less income taxes and reclassifications for amounts included in net income.
Variable Interest Entities
The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. The Company has established certain wholly-owned trusts to issue preferred securities. However, the Company is not considered the primary beneficiary of the trusts. Therefore, the investments in these trusts are reflected as Other Investments, and the related loans from the trusts are reflected as Long-term Debt in the balance sheets. See Note 6 under “Long-Term Debt Payable to Affiliated Trusts” for additional information.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the plan are expected for the year ending December 31, 2008. 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 related trusts to the extent required by the FERC. For the year ending December 31, 2008, postretirement trust contributions are expected to total approximately $23.0 million.
The measurement date for plan assets and obligations is September 30 for each year presented. Pursuant to SFAS No. 158, the Company will be required to change the measurement date for its defined benefit postretirement plans from September 30 to December 31 beginning with the year ending December 31, 2008.
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Pension Plans
The total accumulated benefit obligation for the pension plans was $2.0 billion in 2007 and $2.0 billion in 2006. Changes during the year in the projected benefit obligations and the fair value of plan assets were as follows:
At December 31, 2007, the projected benefit obligations for the qualified and non-qualified pension plans were $2.0 billion and $133 million, respectively. All plan assets are related to the qualified pension plan.
Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk. The actual composition of the Company’s pension plan assets as of the end of the year, along with the targeted mix of assets, is presented below:
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Amounts recognized in the balance sheets related to the Company’s pension plans consist of the following:
Presented below are the amounts included in regulatory assets and regulatory liabilities at December 31, 2007 and 2006 related to the defined benefit pension plans that have not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2008.
The changes in the balances of regulatory assets and regulatory liabilities related to the defined benefit pension plans for the year ended December 31, 2007 are presented in the following table:
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Components of net periodic pension cost (income) were as follows:
Net periodic pension cost (income) is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2007, estimated benefit payments were as follows:
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Other Postretirement Benefits
Changes during the year in the accumulated postretirement benefit obligations (APBO) and in the fair value of plan assets were as follows:
Other postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk. The actual composition of the Company’s other postretirement benefit plan assets as of the end of the year, along with the targeted mix of assets, is presented below:
Amounts recognized in the balance sheets related to the Company’s other postretirement benefit plans consist of the following:
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Presented below are the amounts included in regulatory assets at December 31, 2007 and 2006 related to the other postretirement benefit plans that have not yet been recognized in net periodic postretirement benefit cost along with the estimated amortization of such amounts for 2008:
The change in the balance of regulatory assets related to the other postretirement benefit plans for the year ended December 31, 2007 is presented in the following table:
Components of the other postretirement benefit plans’ net periodic cost were as follows:
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced the Company’s expenses for the years ended December 31, 2007, 2006, and 2005 by approximately $14 million, $16 million, and $11 million, respectively.
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Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the postretirement plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows:
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 2004 for the 2005 plan year using a discount rate of 5.75%.
The Company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.
An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 9.75% for 2008, decreasing gradually to 5.25% through the year 2015, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2007 as follows:
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution up to 6% of an employee’s base salary. Prior to November 2006, the Company matched employee contributions at a rate of 75% up to 6% of the employee’s base salary. Total matching contributions made to the plan for 2007, 2006, and 2005 were $24 million, $21 million, and $20 million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become
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more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements.
Environmental Matters
New Source Review Actions
In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and the Company, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities, including the Company’s Plants Bowen and Scherer. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama after Alabama Power was dismissed from the original action. In these lawsuits, the EPA alleged that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and the Company. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The action against the Company has been administratively closed since the spring of 2001, and the case has not been reopened.
In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving the alleged NSR violations at Plant Miller. The consent decree required Alabama Power to pay $100,000 to resolve the government’s claim for a civil penalty and to donate $4.9 million of sulfur dioxide emission allowances to a nonprofit charitable organization and formalized specific emissions reductions to be accomplished by Alabama Power, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in Alabama granted Alabama Power’s motion for summary judgment and entered final judgment in favor of Alabama Power on the EPA’s claims related to the remaining four plants.
The plaintiffs appealed the district court’s decision to the U.S. Court of Appeals for the Eleventh Circuit, and the appeal was stayed by the Appeals Court pending the U.S. Supreme Court’s decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke Energy case in April 2007. On October 5, 2007, the U.S. District Court for the Northern District of Alabama issued an order in the Alabama Power case indicating a willingness to re-evaluate its previous decision in light of the Supreme Court’s Duke Energy opinion. On December 21, 2007, the Eleventh Circuit vacated the district court’s decision in the Alabama Power case and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court’s decision in the Duke Energy case.
The Company believes it has complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in either of these cases could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
Carbon Dioxide Litigation
In July 2004, attorneys general from eight states, each outside of the Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company, including the Company, and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. The Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and no decision has been issued. The ultimate outcome of these matters cannot be determined at this time.
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Environmental Remediation
Through 2007, the Company recovered environmental costs through its base rates. Beginning in 2005, such rates included an annual accrual of $5.4 million for environmental remediation. Beginning in January 2008, the Company is recovering environmental remediation costs through a new tariff (see “Rate Plans” herein) that includes an annual accrual of $1.2 million for environmental remediation. Environmental remediation expenditures will be charged against the reserve as they are incurred. The annual accrual amount will be reviewed and adjusted in future regulatory proceedings. Under Georgia PSC ratemaking provisions, $22 million had previously been deferred in a regulatory liability account for use in meeting future environmental remediation costs of the Company and was amortized over a three-year period that ended December 31, 2007. As of December 31, 2007, the balance of the environmental remediation liability was $13.5 million.
The Company has been designated as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a large site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites on the Georgia Hazardous Sites Inventory and the CERCLA NPL are anticipated.
The final outcome of these matters cannot now be determined. However, based on the currently known conditions at these sites and nature and extent of activities relating to these sites, management does not believe that additional liabilities, if any, at these sites would be material to the Company’s financial statements.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.
In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales by the Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level.
In late June and July 2007, hearings were held in this proceeding and the presiding administrative law judge issued an initial decision on November 9, 2007 regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the Company to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates and could also result in refunds of up to $5.8 million, plus interest. The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter.
On June 21, 2007, the FERC issued its final rule regarding market-based rate authority. The FERC generally retained its current market-based rate standards. The impact of this order and its effect on the generation dominance proceeding cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet is operated under the Intercompany Interchange Contract (IIC), as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies (including the Company), Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct.
In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms and Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on
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behalf of Southern Power. Southern Company filed with the FERC in November 2006 a compliance plan in connection with the order. On April 19, 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan is not expected to have a material impact on the Company’s financial statements. On November 19, 2007, Southern Company notified the FERC that the plan had been implemented and the FERC division of audits subsequently began an audit pertaining to compliance implementation and related matters, which is ongoing.
Generation Interconnection Agreements
In November 2004, generator company subsidiaries of Tenaska, Inc. (Tenaska), as counterparties to three previously executed interconnection agreements with subsidiaries of Southern Company, including the Company, filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $7.9 million previously paid for interconnection facilities. No other similar complaints are pending with the FERC.
On January 19, 2007, the FERC issued an order granting Tenaska’s requested relief. Although the FERC’s order required the modification of Tenaska’s interconnection agreements, under the provisions of the order the Company determined that no refund was payable to Tenaska. Southern Company requested rehearing asserting that the FERC retroactively applied a new principle to existing interconnection agreements. Tenaska requested rehearing of FERC’s methodology for determining the amount of refunds. The requested rehearings were denied and Southern Company and Tenaska have appealed the orders to the U.S. Circuit Court for the District of Columbia. The final outcome of this matter cannot now be determined.
Right of Way Litigation
In late 2001, certain subsidiaries of Southern Company, including Alabama Power, the Company, Gulf Power, Mississippi Power, and Southern Telecom, Inc. (a subsidiary of SouthernLINC Wireless), were named as defendants in a lawsuit brought by a telecommunications company that uses certain of the defendants’ rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. The Company believes that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. An adverse outcome in this matter, combined with an adverse outcome against the telecommunications company could result in substantial judgments; however, the final outcome cannot now be determined.
Income Tax Matters
The Company’s 2005 through 2007 income tax filings for the State of Georgia included state income tax credits for increased activity through Georgia ports. The Company has also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue has not responded to these claims. On July 24, 2007, the Company filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. If the Company prevails, these claims could have a significant, and possibly material, positive effect on the Company’s net income. If the Company is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on the Company’s cash flow. The ultimate outcome of this matter cannot now be determined. See Note 5 under “Unrecognized Tax Benefits” for additional information.
Property Tax Matters
The Monroe County Board of Tax Assessors (Monroe Board) had issued assessments reflecting substantial increases in the ad valorem tax valuation of the Company’s 22.95% ownership interest in Plant Scherer, which is located in Monroe County, Georgia (Monroe County) for tax years 2003 through 2007.
In November 2004, the Company filed suit against the Monroe Board in the Superior Court of Monroe County. The Company requested injunctive relief prohibiting Monroe County and the Monroe Board from unlawfully changing the value of Plant Scherer and ultimately collecting additional ad valorem taxes from the Company. In December 2005, the court granted Monroe County’s motion for summary judgment. The Company filed an appeal of the Superior Court’s decision to the Georgia Supreme Court.
On March 30, 2007, the Georgia Court of Appeals reversed the trial court and ruled that the Monroe Board had exceeded its legal authority and remanded the case for entry of an injunction prohibiting the Monroe Board from collecting taxes based on its
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independent valuation of Plant Scherer. On July 16, 2007, the Georgia Supreme Court agreed to hear the Monroe Board’s requested review of this decision. On January 9, 2008, the Georgia Supreme Court upheld the appeals court decision. This litigation is now concluded.
Retail Regulatory Matters
Merger
Effective July 1, 2006, Savannah Electric, which was also a wholly owned subsidiary of Southern Company, was merged into the Company. The Company has accounted for the merger in a manner similar to a pooling of interests, and the Company’s financial statements included herein now reflect the merger as though it had occurred on January 1, 2004.
Rate Plans
In December 2004, the Georgia PSC approved the 2004 Retail Rate Plan for the Company. Under the terms of the 2004 Retail Rate Plan, the Company’s earnings were evaluated against a retail return on equity (ROE) range of 10.25% to 12.25%. Two-thirds of any earnings above 12.25% were applied to rate refunds, with the remaining one-third retained by the Company. Retail rates and customer fees increased by approximately $203 million effective January 1, 2005 to cover the higher costs of purchased power, operating and maintenance expenses, environmental compliance, and continued investment in new generation, transmission, and distribution facilities to support growth and ensure reliability. In 2007, the Company refunded 2005 earnings above 12.25% retail ROE. There were no refunds related to earnings for the years 2006 and 2007.
In December 2007, the Georgia PSC approved the 2007 Retail Rate Plan for the years 2008 through 2010. Retail base rates increased by approximately $99.7 million effective January 1, 2008 to provide for cost recovery of transmission, distribution, generation, and other investment, as well as increased operating costs. In addition, the new environmental compliance cost recovery (ECCR) tariff was implemented to recover costs incurred for environmental projects required by state and federal regulations. The ECCR tariff increased rates by approximately $222 million effective January 1, 2008. Under the 2007 Retail Rate Plan, the Company’s earnings will continue to be evaluated against a retail ROE range of 10.25% to 12.25%. Two thirds of any earnings above 12.25% will be applied to rate refunds with the remaining one-third applied to the ECCR tariff. The Company agreed that it will not file for a general base rate increase during this period unless its projected retail ROE falls below 10.25%.
The Company is required to file a general rate case by July 1, 2010, in response to which the Georgia PSC would be expected to determine whether the 2007 Retail Rate Plan should be continued, modified, or discontinued.
Fuel Cost Recovery
The Company has established fuel cost recovery rates approved by the Georgia PSC. In May 2005, the Georgia PSC approved the Company’s request to increase customer fuel rates by approximately 9.5% to recover under recovered fuel costs of approximately $508 million existing as of May 31, 2005 over a four-year period that began June 1, 2005.
In November 2005, the Georgia PSC voted to approve Savannah Electric’s request to increase customer rates to recover estimated under recovered fuel costs of approximately $71.8 million as of November 30, 2005 over an estimated four-year period beginning December 1, 2005, as well as future projected fuel costs.
In March 2006, the Company and Savannah Electric filed a combined request for fuel cost recovery rate changes with the Georgia PSC to be effective July 1, 2006, concurrent with the merger of the companies. In June 2006, the Georgia PSC ruled on the request and approved an increase in the Company’s total annual fuel billings of approximately $400 million. The Georgia PSC order provided for a combined ongoing fuel forecast but reduced the requested increase related to such forecast by $200 million. The Georgia PSC also set a merger transition adjustment (MTA) applicable to customers in the former Savannah Electric service territory so that the fuel rate that became effective on July 1, 2006 plus the MTA equaled the applicable fuel rate paid by such customers as of June 30, 2006. Amounts collected under the MTA were being credited to customers in the original Georgia Power service territory through a merger transition credit through December 31, 2007. The order also required the Company to file for a new fuel cost recovery rate on a semi-annual basis, beginning in September 2006. Accordingly, on September 15, 2006, the Company filed a request to recover fuel costs incurred through August 2006 by increasing the fuel cost recovery rate. On November 13, 2006, under agreement with the Georgia PSC staff, the Company filed a supplementary request reflecting a forecast of annual fuel costs, as well as updated information for previously incurred fuel costs.
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On February 6, 2007, the Georgia PSC approved an increase in the Company’s total annual billings of approximately $383 million effective March 1, 2007. The Georgia PSC order reduced the Company’s requested increase in the forecast of annual fuel costs by $40 million and disallowed $4 million of previously incurred fuel costs. Estimated under recovered fuel costs through February 2007 are being recovered through May 2009 for customers in the original Georgia Power territory and through November 2009 for customers in the former Savannah Electric territory. On December 31, 2006, the Company had an under recovered fuel balance of approximately $898 million, of which approximately $544 million was included in deferred charges and other assets in the balance sheets. As of December 31, 2007, the Company had an under recovered fuel balance of approximately $692 million, of which approximately $307 million is included in deferred charges and other assets in the balance sheets. The order also requires the Company to file for a new fuel cost recovery rate no later than March 1, 2008.
Fuel Hedging Program
The Georgia PSC has approved a natural gas, oil procurement, and hedging program that allows the Company to use financial instruments to hedge price and commodity risk associated with these fuels, subject to certain limits in terms of time, volume, dollars, and physical amounts hedged. The costs of the program, including any net losses, are recovered as a fuel cost through the fuel cost recovery clause. Annual net financial gains from the hedging program, through June 30, 2006, were shared with the retail customers receiving 75% and the Company retaining 25% of the total net gains. Effective July 1, 2006, the profit sharing framework related to the fuel hedging program was terminated. In 2005, the Company had a total net gain of $74.6 million, of which the Company retained $18.6 million. The Company realized net losses in 2006 and 2007 of $66 million and $68 million, respectively.
Nuclear Project Cost Deferral
In June 2006, the Georgia PSC approved the Company’s request to defer for future recovery the early site permit and combined construction and operating license costs, of which the Company’s portion is estimated to total approximately $51 million. At December 31, 2007, approximately $28.4 million is included in deferred charges and other assets. At this point, no final decision has been made regarding actual construction. Any new generation resource must be certified by the Georgia PSC in a separate proceeding.
4. JOINT OWNERSHIP AGREEMENTS
The Company and Alabama Power own equally all of the outstanding capital stock of SEGCO which owns electric generating units with a total rated capacity of 1,020 megawatts, as well as associated transmission facilities. The capacity of the units has been sold equally to the Company and Alabama Power under a contract which, in substance, requires payments sufficient to provide for the operating expenses, taxes, debt service, and return on investment, whether or not SEGCO has any capacity and energy available. The term of the contract extends automatically for two-year periods, subject to either party’s right to cancel upon two year’s notice.
The Company’s share of expenses included in purchased power from affiliates in the statements of income is as follows:
The Company owns undivided interests in Plants Vogtle, Hatch, Scherer, and Wansley in varying amounts jointly with Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG), the city of Dalton, Georgia, Florida Power & Light Company, Jacksonville Electric Authority, and Gulf Power. Under these agreements, the Company has contracted to operate and maintain the plants as agent for the co-owners and is jointly and severally liable for third party claims related to these plants. In addition, the Company jointly owns the Rocky Mountain pumped storage hydroelectric plant with OPC who is the operator of the plant. The Company and Progress Energy Florida, Inc. jointly own a combustion turbine unit (Intercession City) operated by Progress Energy Florida, Inc.
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At December 31, 2007 the Company’s percentage ownership and investment (exclusive of nuclear fuel) in jointly owned facilities in commercial operation were as follows:
At December 31, 2007, the portion of total construction work in progress related to Plants Wansley, Scherer, and Rocky Mountain was $170.3 million, $66.5 million, and $4.0 million, respectively, primarily for environmental projects.
The Company’s proportionate share of its plant operating expenses is included in the corresponding operating expenses in the statements of income.
5. INCOME TAXES
Southern Company files a consolidated federal income tax return and combined income tax returns for the States of Alabama, Georgia, and Mississippi. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if they filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability.
Current and Deferred Income Taxes
The transfer of the Plant McIntosh construction project from Southern Power to the Company in 2005 resulted in a deferred gain to Southern Power for federal income tax purposes. The Company is reimbursing Southern Power for the remaining balance of the related deferred taxes of $4.6 million as it is reflected in Southern Power’s future taxable income. $4.1 million of this payable to Southern Power is included in Other Deferred Credits and $0.5 million is included in Affiliated Accounts Payable in the balance sheets at December 31, 2007.
The transfer of the Dahlberg, Wansley, and Franklin projects to Southern Power from the Company in 2001 and 2002 also resulted in a deferred gain for federal income tax purposes. Southern Power is reimbursing the Company for the remaining balance of the related deferred taxes of $9.5 million as it is reflected in the Company’s future taxable income. $7.7 million of this receivable from Southern Power is included in Other Deferred Debits and $1.8 million is included in Affiliated Accounts Receivable in the balance sheets at December 31, 2007.
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Details of income tax provisions are as follows:
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:
At December 31, 2007, tax-related regulatory assets were $533 million and tax-related regulatory liabilities were $147 million. The assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest. The liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits.
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In accordance with regulatory requirements, deferred investment tax credits are amortized over the 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 $13.0 million annually in 2007, 2006, and 2005. At December 31, 2007, all investment tax credits available to reduce federal income taxes payable had been utilized.
Effective Tax Rate
A reconciliation of the federal statutory income tax rate to the effective income tax rate was as follows:
The decrease in 2007’s effective tax rate is the result of the tax benefits associated with donations and an increase in state tax credits and the federal manufacturer’s tax deduction.
In 2007, the Company donated 2,200 acres of land in the Tallulah Gorge State Park to the State of Georgia. The estimated value of this donation along with an increase in non-taxable AFUDC equity and available state tax credits as well as higher federal tax deductions caused a lower effective income tax rate for the year ended 2007, when compared to prior years. For additional information regarding litigation related to state tax credits, see Note 3 under “Income Tax Matters.”
The American Jobs Creation Act of 2004 created a tax deduction for the portion of income attributable to United States production activities as defined in Internal Revenue Code Section 199 (production activities deduction). The deduction is equal to a stated percentage of the taxpayer’s qualified production activities income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for years 2007 through 2009, and a 9% rate applicable for all years after 2009. This increase from 3% in 2006 to 6% was one of several factors that increased the Company’s 2007 deduction by $18.6 million in tax deductions. The resulting tax benefit was $6.5 million.
Unrecognized Tax Benefits
On January 1, 2007, the Company adopted FIN 48 which requires companies to determine whether it is “more likely than not” that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. It also provides guidance on the recognition, measurement, and classification of income tax uncertainties, along with any related interest and penalties.
Prior to adoption of FIN 48, the Company had unrecognized tax benefits which were previously accrued under Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies” of approximately $62 million. Upon adoption of FIN 48, an additional $3 million of unrecognized tax benefits were recorded, which resulted in a total balance of $65 million. The $3 million relates to tax positions for which ultimate deductibility is highly certain, but for which there is uncertainty as to the timing of such deductibility. Of the total $65 million unrecognized tax benefits, $62 million would impact the Company’s effective tax rate if recognized. For 2007, the total amount of unrecognized tax benefits increased by $24.2 million, resulting in a balance of $89.2 million as of December 31, 2007.
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Changes during the year in unrecognized tax benefits were as follows:
Impact on the Company’s effective tax rate, if recognized, is as follows:
Accrued interest for unrecognized tax benefits:
The Company classifies interest on tax uncertainties as interest expense. Net interest accrued for the year ended December 31, 2007 was $7.1 million. The Company did not accrue any penalties on uncertain tax positions.
The IRS has audited and closed all tax returns prior to 2004. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2002.
It is reasonably possible that the amount of the unrecognized benefit with respect to certain of the Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The possible settlement of the Georgia state tax credits litigation, production activities deduction methodology, and/or the conclusion or settlement of federal or state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. See Note 3 under “Income Tax Matters” herein for additional information.
6. FINANCING
Outstanding Classes of Capital Stock
The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized. The Company has shares of its Class A preferred stock, preference stock, and common stock outstanding. The Company’s Class A preferred stock ranks senior to the Company’s preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. The Company’s preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. Certain series of the Class A preferred stock and preference stock are subject to redemption at the option of the Company on or after a specified date (typically 5 or 10 years after the date of issuance) at a redemption price equal to 100% of the liquidation amount of the stock. In addition, the Company may redeem the outstanding series of the preference stock at a redemption price equal to 100% of the liquidation amount plus a make-whole premium based on the present value of the liquidation amount and future dividends.
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Dividend Restrictions
The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
Long-Term Debt Payable to Affiliated Trusts
The Company has formed certain wholly owned trust subsidiaries for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to the Company through the issuance of junior subordinated notes totaling $206 million, which constitute substantially all of the assets of these trusts and are reflected in the balance sheets as “Long-term Debt.” The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective trusts’ payment obligations with respect to these securities. During 2007, the Company redeemed junior subordinated notes and the related trust preferred securities issued by Georgia Power Capital Trusts V and VI. At December 31, 2007, preferred securities of $200 million were outstanding. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities.
Securities Due Within One Year
A summary of the scheduled maturities and redemptions of securities due within one year at December 31 is as follows:
Redemptions and/or maturities through 2012 applicable to total long-term debt are as follows: $199 million in 2008; $279 million in 2009; $4 million in 2010; $115 million in 2011; and $288 million in 2012.
Pollution Control Bonds
Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The Company has incurred obligations in connection with the sale by public authorities of tax-exempt pollution control revenue bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2007 was $1.9 billion. Proceeds from certain issuances are restricted until the expenditures are incurred.
Senior Notes
The Company issued $1.5 billion aggregate principal amount of unsecured senior notes in 2007. The proceeds of the issuance were used to repay a portion of the Company’s short term indebtedness, fund note maturities, redeem long-term debt payable to affiliated trusts, and fund the Company’s continuous construction program. At December 31, 2007 and 2006, the Company had $4.0 billion and $2.8 billion of senior notes outstanding, respectively. These senior notes are effectively subordinated to all secured debt of the Company, which aggregated $71 million at December 31, 2007.
Capital Leases
Assets acquired under capital leases are recorded in the balance sheets as utility plant in service, and the related obligations are classified as long-term debt. At December 31, 2007 and 2006, the Company had a capitalized lease obligation for its corporate headquarters building of $69 million and $72 million, respectively, with an interest rate of 8.1%. For ratemaking purposes, the Georgia PSC has treated the lease as an operating lease and has allowed only the lease payments in cost of service. The difference between the accrued expense and the lease payments allowed for ratemaking purposes has been deferred and is being amortized to expense as ordered by the Georgia PSC. See Note 1 under “Regulatory Assets and Liabilities.” At December 31, 2007 and 2006, the Company had capitalized lease obligations of $1.9 million for its vehicles and $4.1 million for its vehicles and the Plant Kraft coal unloading dock, respectively. However, for ratemaking purposes, these obligations are treated as operating leases and, as such, lease payments are charged to expense as incurred. The annual expense incurred for these leases in 2007, 2006, and 2005 was $9.2 million, $9.6 million, and $9.7 million, respectively. In March 2007, the Savannah Economic Development Authority Taxable Industrial
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Georgia Power Company 2007 Annual Report
Revenue Bonds First Series 1996 were redeemed; therefore, as of December 31, 2007, the Company no longer has a capital lease obligation for the Plant Kraft unloading dock.
Bank Credit Arrangements
At the beginning of 2008, the Company had credit arrangements with banks totaling $1.2 billion, of which $8 million was used to support outstanding letters of credit. Of these facilities, $40 million expires during 2008, with the remaining $1.1 billion expiring in 2012. The facility that expires in 2008 provides the option of converting borrowings into a two-year term loan. The Company expects to renew its facilities, as needed, prior to expiration. The agreements contain stated borrowing rates. All the agreements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees are less than 1/8 of 1% for the Company. Compensating balances are not legally restricted from withdrawal.
The credit arrangements contain covenants that limit the level of indebtedness to capitalization to 65%, as defined in the arrangements. For purposes of these definitions, indebtedness excludes the long-term debt payable to affiliated trusts and, in certain cases, other hybrid securities. In addition, the credit arrangements contain cross default provisions that would trigger an event of default if the Company defaulted on other indebtedness above a specified threshold. At December 31, 2007, the Company was in compliance with all such covenants. None of the arrangements contain material adverse change clauses at the time of borrowings.
The $1.2 billion of unused credit arrangements provides liquidity support to the Company’s variable rate pollution control bonds and its commercial paper borrowing. The amount of variable rate pollution control bonds outstanding requiring liquidity support as of December 31, 2007 was $301 million. In addition, the Company borrows under a commercial paper program and an extendible commercial note program. The amount of commercial paper outstanding at December 31, 2007, 2006, and 2005 was $616 million, $733 million, and $327 million, respectively. There were no outstanding extendible commercial notes at December 31, 2007. Commercial paper is included in notes payable on the balance sheets.
During 2007, the peak amount of short-term debt outstanding was $1.1 billion and the average amount outstanding was $638 million. The average annual interest rate on short-term debt in 2007 was 5.3%.
Financial Instruments
The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. See Note 3 under “Retail Regulatory Matters - Fuel Hedging Program” for information on the Company’s fuel hedging program. The Company also enters into hedges of forward electricity sales. There was no material ineffectiveness related to energy related derivatives recorded in earnings in any period presented. At December 31, 2007, the $0.4 million fair value of net losses of derivative energy contracts were reflected in the financial statements as regulatory assets. The fair value gain or loss for hedges that are recoverable through the regulatory fuel clauses are recorded in regulatory assets and liabilities and are recognized in earnings at the same time the hedged items affect earnings. The Company has energy-related hedges in place up to and including 2010. The Company enters into derivatives to hedge exposure to interest rate changes. Derivatives related to variable rate securities or forecasted transactions are accounted for as cash flow hedges. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. As such, no material ineffectiveness has been recorded in earnings for any period presented.
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At December 31, 2007, the Company had $539 million notional amounts of interest derivatives accounted for as cash flow hedges outstanding with net fair value gains/(losses) as follows:
*
Interest rate collar with variable rate based on a percentage of one-month LIBOR (showing rate cap)
**
Hedged using the Securities Industry and Financial Markets Association Municipal Swap Index (SIFMA), (Formerly the Bond Market Association/PSA Municipal Swap Index)
Subsequent to December 31, 2007, the Company entered into $601 million notional amounts of interest rate swaps related to variable rate debt through December 2009.
The fair value gain or loss for cash flow hedges is recorded in other comprehensive income and is reclassified into earnings at the same time the hedged items affect earnings. In 2007, 2006, and 2005, the Company settled gains/(losses) totaling $12.1 million, $(3.9) million, and $0.9 million, respectively, upon termination of certain interest derivatives at the same time it issued debt. The effective portion of these gains/(losses) have been deferred in other comprehensive income and will be amortized to interest expense over the life of the original interest derivative. Amounts reclassified from other comprehensive income to interest expense were immaterial for all periods presented. For 2008, pre-tax losses of approximately $3 million are expected to be reclassified from other comprehensive income to interest expense. The Company has interest related hedges in place through 2019 and has realized gains/(losses) that are being amortized through 2037.
7. COMMITMENTS
Construction Program
The Company currently estimates property additions to be approximately $2.0 billion, $2.0 billion, and $1.8 billion, in 2008, 2009, and 2010, respectively. These amounts include $116 million, $138 million, and $128 million in 2008, 2009, and 2010, respectively, for construction expenditures related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included under “Fuel Commitments.” The construction program is subject to periodic review and revision, and actual construction costs may vary from estimates because of numerous factors, including, but not limited to, changes in business conditions, changes in FERC rules and regulations, revised load growth estimates, changes in environmental regulations, changes in existing nuclear plants to meet new regulatory requirements, increasing costs of labor, equipment, and materials, and cost of capital. At December 31, 2007, significant purchase commitments were outstanding in connection with the construction program.
Long-Term Service Agreements
The Company has entered into a Long-Term Service Agreement (LTSA) with General Electric (GE) for the purpose of securing maintenance support for the combustion turbines at the Plant McIntosh combined cycle facility. In summary, the LTSA stipulates that GE will perform all planned inspections on the covered equipment, which includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in each contract.
In general, this LTSA is in effect through two major inspection cycles per unit. Scheduled payments to GE, which are subject to price escalation, are made quarterly based on actual operating hours of the respective units. Total payments to GE under this agreement are currently estimated at $187.7 million over the remaining term of the agreement, which is currently projected to be approximately 10 years. However, the LTSA contains various cancellation provisions at the option of the Company.
The Company has also entered into an LTSA with GE through 2014 for neutron monitoring system parts and electronics at Plant Hatch. Total remaining payments to GE under this agreement are currently estimated at $9.2 million. The contract contains
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Georgia Power Company 2007 Annual Report
cancellation provisions at the option of the Company. Payments made to GE prior to the performance of any work are recorded as a prepayment in the balance sheets. Work performed by GE is capitalized or charged to expense as appropriate net of any joint owner billings, based on the nature of the work.
The Company has entered into a LTSA with Mitsubishi Power Systems Americas, Inc. (MPS) for the purpose of providing certain parts and maintenance services for the three combined cycle units under construction at Plant McDonough, which are scheduled to go into service in February 2011, June 2011, and June 2012, respectively. The LTSA stipulates that MPS will perform all planned maintenance on each covered unit which includes the cost of all materials and services. MPS is also obligated to cover costs of unplanned maintenance on the gas turbines subject to limits specified in the LTSA.
This LTSA will commence in 2011 and is in effect through two major inspection cycles per covered unit. Periodic payments to MPS are to be made quarterly and will also be made based on the scheduled inspections for the respective covered units. Payments to MPS under this agreement, which are subject to price escalation, are currently estimated to be $536.8 million for the term of the agreement which is expected to be between 12 and 13 years. However, the LTSA contains various termination provisions at the option of the Company.
Limestone Commitments
As part of the Company’s program to reduce sulfur dioxide emissions from certain of its coal plants, the Company is constructing certain equipment and has entered into various long-term commitments for the procurement of limestone to be used in such equipment. Contracts are structured with tonnage minimums and maximums in order to account for changes in coal burn and sulfur content. The Company has a minimum contractual obligation of 3.8 million tons, equating to approximately $114.6 million through 2019. Estimated expenditures over the next five years are $4.5 million in 2008, $10.2 million in 2009, $19.2 million in 2010, $14.6 million in 2011, and $14.9 million in 2012.
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide emission allowances. Natural gas purchase commitments contain fixed volumes with prices based on various indices at the time of delivery. Amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2007.
Total estimated minimum long-term obligations at December 31, 2007 were as follows:
Additional commitments for fuel will be required to supply the Company’s future needs. Total charges for nuclear fuel included in fuel expense were $79 million, $71 million and $70 million for the years 2007, 2006, and 2005, respectively.
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. The creditworthiness of Southern Power is currently inferior to the creditworthiness of the traditional operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure they 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.
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Georgia Power Company 2007 Annual Report
Purchased Power Commitments
The Company has commitments regarding a portion of a 5% interest in Plant Vogtle owned by MEAG that are in effect until the latter of the retirement of the plant or the latest stated maturity date of MEAG’s bonds issued to finance such ownership interest. The payments for capacity are required whether or not any capacity is available. The energy cost is a function of each unit’s variable operating costs. Portions of the capacity payments relate to costs in excess of Plant Vogtle’s allowed investment for ratemaking purposes. The present value of these portions at the time of the disallowance was written off. Generally, the cost of such capacity and energy is included in purchased power from non-affiliates in the statements of income. Capacity payments totaled $46 million, $49 million, and $54 million in 2007, 2006, and 2005, respectively. The Company also has entered into other various long-term power purchase agreements (PPAs). Estimated total long-term obligations under these commitments at December 31, 2007 were as follows:
Operating Leases
The Company has entered into various operating leases with various terms and expiration dates. Rental expenses related to these operating leases totaled $31 million for 2007, $33 million for 2006, and $39 million for 2005.
At December 31, 2007, estimated minimum lease payments for these noncancelable operating leases were as follows:
In addition to the rental commitments above, the Company has obligations upon expiration of certain rail car leases with respect to the residual value of the leased property. These leases expire in 2011 and the Company’s maximum obligation is $40.7 million. At the termination of the leases, at the Company’s option, the Company 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 obligation. A portion of the rail car lease obligations is shared with the joint owners of Plants Scherer and Wansley. A majority of the rental expenses related to the rail car leases are fully recoverable through the fuel cost recovery clause as ordered by the Georgia PSC and the remaining portion is recovered through base rates.
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Georgia Power Company 2007 Annual Report
Guarantees
Alabama Power has guaranteed unconditionally the obligation of SEGCO under an installment sale agreement for the purchase of certain pollution control facilities at SEGCO’s generating units, pursuant to which $24.5 million principal amount of pollution control revenue bonds are outstanding. Alabama Power has also guaranteed $50 million in senior notes issued by SEGCO. The Company has agreed to reimburse Alabama Power for the pro rata portion of such obligations corresponding to the Company’s then proportionate ownership of stock of SEGCO if Alabama Power is called upon to make such payment under its guaranty.
As discussed earlier in this Note under “Operating Leases,” the Company has entered into certain residual value guarantees related to rail car leases.
8. STOCK OPTION PLAN
Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. As of December 31, 2007, 1,658 current and former employees of the Company participated in the stock option plan. The maximum number of shares of Southern Company common stock that may be issued under this plan may not exceed 40 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however for employees who are eligible for retirement the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. For certain stock option awards a change in control will provide accelerated vesting.
The Company’s activity in the stock option plan for 2007 is summarized below:
The number of stock options vested, and expected to vest in the future, as of December 31, 2007 was not significantly different from the number of stock options outstanding at December 31, 2007 as stated above. At December 31, 2007, the weighted average remaining contractual term for the options outstanding and options exercisable was 6.4 years and 5.2 years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $61.5 million and $51.4 million, respectively.
As of December 31, 2007, there was $2.3 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 10 months.
The total intrinsic value of options exercised during the years ended December 31, 2007, 2006, and 2005 was $17.4 million, $10.3 million, and $24.2 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $6.7 million, $4.0 million, and $9.4 million, respectively, for the years ended December 31, 2007, 2006, and 2005.
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 the Company’s Plants Hatch and Vogtle. The Act provides funds up to $10.8 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $300 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors. The Company could be assessed up to $101 million per incident for each licensed reactor it operates but not more than an
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NOTES (continued)
Georgia Power Company 2007 Annual Report
aggregate of $15 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company, based on its ownership and buyback interests, is $203 million, per incident, but not more than an aggregate of $30 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 on or before August 31, 2008.
The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members’ nuclear generating facilities.
Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.3 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.
NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member’s nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. The Company purchases the maximum limit allowed by NEIL, subject to ownership limitations. Each facility has elected a 12-week waiting period.
Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for the Company under the NEIL policies would be $51 million.
Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12 month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.
All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.
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10. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for 2007 and 2006 is as follows:
The Company’s business is influenced by seasonal weather conditions.
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SELECTED FINANCIAL AND OPERATING DATA 2003-2007
Georgia Power Company 2007 Annual Report
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SELECTED FINANCIAL AND OPERATING DATA 2003-2007 (continued)
Georgia Power Company 2007 Annual Report
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GULF POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Gulf Power Company 2007 Annual Report
The management of Gulf Power Company (the “Company”) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Under management’s supervision, an evaluation of the design and effectiveness of the Company’s internal control over financial reporting was conducted based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2007.
This Annual Report does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report.
/s/ Susan N. Story
Susan N. Story
President and Chief Executive Officer
/s/ Ronnie R. Labrato
Ronnie R. Labrato
Vice President and Chief Financial Officer
February 25, 2008
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Gulf Power Company
We have audited the accompanying balance sheets and statements of capitalization of Gulf Power Company (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2007 and 2006, 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, 2007. 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 II-251 to II-280) present fairly, in all material respects, the financial position of Gulf Power Company at December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the financial statements, in 2006 the Company changed its method of accounting for the funded status of defined benefit pension and other postretirement plans.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 25, 2008
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Gulf Power Company 2007 Annual Report
OVERVIEW
Business Activities
Gulf Power Company (the Company) operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in northwest Florida and 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 stable regulatory environment, to achieve energy sales growth, and to effectively manage and secure timely recovery of rising costs. These costs include those related to growing demand, increasingly stringent environmental standards, fuel prices, and storm restoration costs. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future.
In July 2006, the Florida Public Service Commission (PSC) extended the storm-recovery surcharge currently being collected by the Company until June 2009. See Notes 1 and 3 to the financial statements under “Property Damage Reserve” and “Retail Regulatory Matters - Storm Damage Cost Recovery,” respectively, for additional information.
Key Performance Indicators
In striving to maximize shareholder value while providing cost-effective energy to over 425,000 customers, the Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. The Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company’s results.
Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of 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 2007 Peak Season EFOR of 2.82% 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, expected weather conditions, and expected capital expenditures. The performance for 2007 was better than target for these reliability measures. Net income after dividends on preferred and preference stock is the primary component of the Company’s contribution to Southern Company’s earnings per share goal.
The Company’s 2007 results compared with its targets for some of these key indicators are reflected in the following chart:
See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The financial performance achieved in 2007 reflects the continued emphasis that management places on these indicators, as well as the commitment shown by employees in achieving or exceeding management’s expectations.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2007 Annual Report
Earnings
The Company’s 2007 net income after dividends on preferred and preference stock was $84.1 million, an increase of $8.1 million from the previous year. In 2006, earnings were $76.0 million, an increase of $0.8 million from the previous year. In 2005, earnings were $75.2 million, an increase of $7.0 million from the previous year. The increase in earnings in 2007 was due primarily to increases in retail revenues, earnings on additional investments in environmental controls through the environment cost recovery provision, and related allowance for equity funds used during construction partially offset by non-fuel operating expenses. The increase in earnings in 2006 was due primarily to higher operating revenues partially offset by higher operating expenses, higher financing costs, and increases in depreciation expense. The increase in earnings in 2005 was due primarily to higher retail sales and lower non-fuel operating expenses, excluding expenses related to Hurricane Ivan storm damage, which were offset by revenues and did not affect earnings. See FUTURE EARNINGS POTENTIAL - “PSC Matters - Storm Damage Cost Recovery” herein.
RESULTS OF OPERATIONS
A condensed statement of income follows:
Operating Revenues
Operating revenues increased in 2007 when compared to 2006 and 2005. The following table summarizes the changes in operating revenues for the past three years:
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2007 Annual Report
Retail revenues increased $54.3 million, or 5.7%, in 2007, $87.2 million, or 10.1%, in 2006, and $128.0 million, or 17.4%, in 2005. The significant factors driving these changes are shown in the table above.
Revenues associated with changes in rates and pricing include cost recovery provisions for energy conservation costs and environmental compliance costs. Annually, the Company petitions the Florida PSC for recovery of projected costs, including any true-up amount from prior periods, and approved rates are implemented each January. The recovery provisions include related expenses and a return on average net investment. See Note 3 to the financial statements under “Retail Regulatory Matters - Environmental Cost Recovery” for additional information.
Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, and purchased power capacity costs. Annually, the Company petitions the Florida PSC for recovery of projected fuel and purchased power costs, including any true-up amount from prior periods, and approved rates are implemented each January. Cost recovery provisions also include revenues related to the recovery of storm damage restoration costs. The recovery provisions generally equal the related expenses and have no material effect on net income. See Note 1 to the financial statements under “Revenues” and “Property Damage Reserve” and Note 3 to the financial statements under “Retail Regulatory Matters - Storm Damage Cost Recovery” for additional information.
Total wholesale revenues were $196.7 million in 2007, a decrease of $8.5 million, or 4.2%, compared to 2006, primarily due to decreased energy sales to affiliates at a lower cost per kilowatt-hour (KWH) supplied by lower-cost generating resources. Total wholesale revenues were $205.2 million in 2006, an increase of $29.5 million, or 16.8%, compared to 2005, primarily due to increased energy sales to affiliates to serve their territorial energy requirements. Total wholesale revenues were $175.7 million in 2005, a decrease of $8.1 million, or 4.4%, compared to 2004, primarily due to lower energy sales to affiliates resulting from decreases in the Company’s available generation as a result of outages at Plants Crist and Smith.
Wholesale revenues from sales to non-affiliates include unit power sales under long-term contracts to other Florida utilities. Wholesale revenues from contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment. Energy is generally sold at variable cost. The capacity and energy components under these unit power sales contracts were as follows:
Wholesale revenues from sales to affiliated companies within the Southern Company system will vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliated sales and purchases are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the Federal Energy Regulatory Commission (FERC). These transactions do not have a significant impact on earnings, since the energy is generally sold at marginal cost and energy purchases are generally offset by revenues through the Company’s fuel cost recovery clause.
Other operating revenues increased $10.2 million in 2007, primarily due to other energy services and an increase in franchise fees, which were proportional to changes in revenue. The increased revenues from other energy services did not have a material impact on earnings since they were generally offset by associated expenses. Other operating revenues increased $3.6 million in both 2006 and 2005, primarily due to an increase in franchise fees, which were proportional to changes in revenue.
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Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2007 and the percent change by year were as follows:
Residential energy sales increased 0.9% in 2007, compared to 2006, primarily due to more favorable weather conditions and customer growth, partially offset by customer response to higher prices. Residential energy sales increased 2.0% in 2006, compared to 2005, primarily due to more favorable weather conditions and customer growth. Residential energy sales increased 2.0% in 2005, compared to 2004, primarily due to customer growth, partially offset by unfavorable weather conditions.
Commercial energy sales increased 3.3% in 2007, compared to 2006, primarily due to more favorable weather conditions and customer growth. Commercial energy sales increased 2.9% in 2006, compared to 2005, primarily due to more favorable weather conditions and customer growth. Commercial energy sales increased 1.1% in 2005, compared to 2004, primarily due to customer growth, partially offset by unfavorable weather conditions.
Industrial energy sales decreased 4.1% in 2007, compared to 2006, primarily due to a conversion project by a major forest products manufacturer and a production process change by a major petroleum company. Industrial energy sales decreased 1.1% in 2006, compared to 2005, due to reduced demand for and production of building materials and a conversion project by a major paper manufacturer. Industrial energy sales increased 2.3% in 2005, compared to 2004, primarily due to additional sales to customers with gas-fired co-generation resulting from high natural gas prices.
Wholesale energy sales to non-affiliates increased 7.1% in 2007, decreased 9.4% in 2006, and increased 1.7% in 2005, each compared to the prior year primarily as a result of fluctuations in the fuel cost to produce energy sold to non-affiliated utilities under both long-term and short-term contracts. The degree to which oil and natural gas prices, which are the primary fuel sources for these customers, differ from the Company’s fuel costs will influence these changes in sales. The fluctuations in sales have a minimal effect on earnings because the energy is generally sold at marginal cost.
Wholesale energy sales to affiliates decreased 1.8% in 2007 compared to 2006, primarily due to the availability of lower cost generation resources at affiliated companies. Wholesale energy sales to affiliates increased 48.6% in 2006 compared to 2005, primarily due to increased territorial energy requirements of affiliates. Wholesale energy sales to affiliates decreased 36.8% in 2005 compared to 2004, due to decreases in the Company’s available generation as a result of outages at Plants Crist and Smith.
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.
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Details of the Company’s electricity generated and purchased were as follows:
Fuel expense was $573.4 million in 2007, an increase of $38.4 million, or 7.2%, above the prior year costs. This increase was the result of a $28.3 million increase in the average cost of fuel and a $10.1 million increase related to total KWHs generated. Fuel expense was $535 million in 2006, an increase of $119.1 million, or 28.7%, above the prior year costs. This increase was the result of an $82.4 million increase in the average cost of fuel and a $36.7 million increase related to total KWHs generated. Fuel expense was $416 million in 2005, an increase of $48.6 million, or 13.2%, above the prior year costs. This increase was the result of a $67.5 million increase in the average cost of fuel, partially offset by $18.9 million decrease related to total KWHs generated.
Purchased power expense was $71.5 million in 2007, a decrease of $2.3 million, or 3.2%, below the prior year costs. This decrease was the result of a $6.5 million decrease in total KWHs purchased, offset by a $4.2 million increase resulting from the higher average cost per net KWH. Purchased power expense was $73.8 million in 2006, a decrease of $24.6 million, or 25.0%, below the prior year costs. This decrease was the result of a $24.9 million decrease in total KWHs purchased and a $0.3 million increase resulting from the higher average cost per net KWH. Purchased power expense was $98.4 million in 2005, an increase of $32.5 million, or 49.3%, above the prior year costs. This increase was the result of a $7.6 million decrease in total KWHs purchased and a $40.1 million increase resulting from the higher average cost per net KWH.
While there has been a significant upward trend in the cost of coal and natural gas since 2003, prices moderated somewhat in 2006 and 2007. Coal prices have been influenced by a worldwide increase in demand from developing countries, as well as increases in mining and fuel transportation costs. While demand for natural gas in the United States continued to increase in 2007, natural gas supplies have also risen due to increased production and higher storage levels.
Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s fuel cost recovery provisions. See FUTURE EARNINGS POTENTIAL - “PSC Matters - Fuel Cost Recovery” herein and Note 3 to the financial statements for additional information.
Other Operations and Maintenance Expenses
In 2007, other operations and maintenance expenses increased $10.9 million, or 4.2%, compared to the prior year primarily due to a $5.0 million increase in other energy services and a $4.3 million increase in severance costs associated with a reorganization. The increased expenses from other energy services did not have a material impact on earnings since they were generally offset by associated revenue. In 2007, the Company offered both voluntary and involuntary severance to a number of employees in connection with a reorganization of certain functions. In 2006, other operations and maintenance expenses increased $9.7 million, or 3.9%, compared to the prior year primarily due to a $4.2 million increase in the recovery of incurred costs for storm damage activity as approved by the Florida PSC, a $1.9 million increase in employee benefit expenses, and a $1.1 million increase in property insurance costs. In 2005, other operations and maintenance expenses increased $20.1 million, or 8.7%, compared to the prior year primarily due to the recovery of $20.4 million in Hurricane Ivan restoration costs as approved by the Florida PSC. Since these storm damage expenses were recognized as revenues were recorded, there was no impact on net income. See FUTURE EARNINGS POTENTIAL - “PSC Matters - Storm Damage Cost Recovery” herein and Notes 1 and 3 to the financial statements under “Property Damage Reserve” and “Retail Regulatory Matters - Storm Damage Cost Recovery,” respectively, for additional information.
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Depreciation and Amortization
Depreciation and amortization expense decreased $3.6 million, or 4.0%, in 2007 compared to the prior year primarily due to new depreciation rates implemented in January 2007. Depreciation and amortization expense increased $4.2 million, or 4.9%, in 2006 compared to the prior year primarily due to the construction of environmental control projects at Plants Crist and Daniel that were placed in service in 2005. Depreciation and amortization expense increased $2.2 million, or 2.7%, in 2005 compared to the prior year primarily due to the completion of environmental control projects at Plant Crist Unit 7.
Taxes Other than Income Taxes
Taxes other than income taxes increased $3.2 million, or 4.0%, in 2007, $3.4 million, or 4.5%, in 2006, and $6.5 million, or 9.3%, in 2005 primarily due to increases in franchise and gross receipts taxes, which were directly related to the increase in retail revenues.
Interest Income
Interest income increased $0.1 million, or 2.3%, in 2007 and increased $1.4 million, or 37.4%, in 2006 compared to the prior years primarily due to interest received related to the recovery of financing costs associated with the fuel clause and incurred costs for storm damage activity as approved by the Florida PSC. Interest income increased $2.6 million, or 210.8%, in 2005 compared to the prior year primarily due to interest received from a tax refund resulting from Hurricane Ivan and interest received related to the recovery of financing costs associated with Hurricane Ivan. See FUTURE EARNINGS POTENTIAL - “Storm Damage Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters - Storm Damage Cost Recovery” for additional information.
Interest Expense, Net of Amounts Capitalized
Interest expense, net of amounts capitalized increased $0.5 million, or 1.2%, in 2007 compared to the prior year as the result of the issuance of $110 million and $85 million in senior notes in December 2006 and June 2007, respectively. These increases were offset by the extinguishment of $25 million aggregate principal amount of first mortgage bonds in 2006, the redemption of $41.2 million of junior subordinated notes and the related trust preferred and common securities of Gulf Power Capital Trust IV, and a decrease in outstanding short-term indebtedness. Interest expense, net of amounts capitalized increased $3.8 million, or 9.5%, in 2006 compared to the prior year as the result of higher interest rates on variable rate pollution control bonds, increased levels of short-term borrowings at higher interest rates, and the issuance of $60 million in senior notes in August 2005. These increases were partially offset by the maturity of a $100 million bank note in October 2005 and the extinguishment of $30 million aggregate principal amount of first mortgage bonds in 2005. Interest expense increased $5.4 million, or 15.4%, in 2005 compared to the prior year as the result of higher interest rates on variable rate pollution control bonds, an increase in outstanding short-term indebtedness as a result of hurricane-related costs, and the issuance of $72.2 million of junior subordinated notes and the related trust preferred and common securities of Gulf Power Capital Trusts III and IV in 2004.
Allowance for Equity Funds Used During Construction
Allowance for equity funds used during construction (AFUDC) increased $2.0 million, or 553.6%, in 2007 compared to the prior year primarily due to construction of an environmental control project at Plant Crist. AFUDC decreased $0.8 million, or 68.9%, in 2006 compared to the prior year primarily due to the completion of an environmental control project at Plant Crist Unit 7 during 2005. AFUDC decreased $0.7 million, or 37.1%, in 2005 compared to the prior year primarily due to the construction and completion of an environmental control project at Plant Crist Unit 7. See FUTURE EARNINGS POTENTIAL - “Environmental Matters - Environmental Statutes and Regulations” herein and Note 1 to the financial statements under “Allowance for Funds Used During Construction (AFUDC)” for additional information.
Other Deductions
Other deductions increased $0.3 million, or 6.7%, in 2007, increased $1.5 million, or 52.9%, in 2006, and decreased $1.4 million, or 32.2%, in 2005 compared to the prior years primarily as a result of changes in charitable contributions.
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Effects of Inflation
The Company is subject to rate regulation based on the recovery of historical costs. When historical costs are included, or when inflation exceeds projected costs used in rate regulation or market-based prices, the effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. In addition, the income tax laws are based on historical costs. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations such as long-term debt, preference stock, and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed in the Company’s approved electric rates.
FUTURE EARNINGS POTENTIAL
General
The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in northwest Florida and to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the Florida PSC under cost-based regulatory principles. Prices for electricity relating to power purchase agreements (PPAs), interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES - “Application of Critical Accounting Policies and Estimates - Electric Utility Regulation” herein and Note 3 to the financial statements 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 business of selling electricity. These factors include the ability of the Company to maintain a stable regulatory environment that continues to allow for the recovery of all prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the Company’s service area.
Environmental Matters
Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. Some of the factors driving the potential for such an increase are higher commodity costs, market demand for labor, and scope additions and clarifications. The timing, specific requirements, and estimated costs could also change as environmental statutes and regulations are adopted or modified. See Note 3 to the financial statements under “Environmental Matters” for additional information.
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama after Alabama Power was dismissed from the original action. In these lawsuits, the EPA alleged that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation relating to the Company’s Plant Crist and a unit partially owned by the Company at Plant Scherer. See Note 4 to the financial statements for information on the Company’s ownership interest in Plant Scherer Unit 3. In early 2000, the EPA filed a motion to amend its complaint to add the allegations in the notices of violation and to add the Company as a defendant. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not refiled. The action against Georgia Power has been administratively closed since the spring of 2001, and the case has not been reopened.
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In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving the alleged NSR violations at Plant Miller. The consent decree required Alabama Power to pay $100,000 to resolve the government’s claim for a civil penalty and to donate $4.9 million of sulfur dioxide emission allowances to a nonprofit charitable organization and formalized specific emissions reductions to be accomplished by Alabama Power, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in Alabama granted Alabama Power’s motion for summary judgment and entered final judgment in favor of Alabama Power on the EPA’s claims related to the remaining plants.
The plaintiffs appealed the district court’s decision to the U.S. Court of Appeals for the Eleventh Circuit, and the appeal was stayed by the Appeals Court pending the U.S. Supreme Court’s decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke Energy case in April 2007. On October 5, 2007, the U.S. District Court for the Northern District of Alabama issued an order in the Alabama Power case indicating a willingness to re-evaluate its previous decision in light of the Supreme Court’s Duke Energy opinion. On December 21, 2007, the Eleventh Circuit vacated the district court’s decision in the Alabama Power case and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court’s decision in the Duke Energy case.
The Company believes it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in this matter could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
The EPA has issued a series of proposed and final revisions to its NSR regulations under the Clean Air Act, many of which have been subject to legal challenges by environmental groups and states. In June 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s revisions to NSR regulations that were issued in December 2002 but vacated portions of those revisions addressing the exclusion of certain pollution control projects. These regulatory revisions have been adopted by the State of Florida. In March 2006, the U.S. Court of Appeals for the District of Columbia Circuit also vacated an EPA rule which sought to clarify the scope of the existing routine maintenance, repair, and replacement exclusion. The EPA has also published proposed rules clarifying the test for determining when an emissions increase subject to the NSR permitting requirements has occurred. The impact of these proposed rules will depend on adoption of the final rules by the EPA and the State of Florida’s implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.
Carbon Dioxide Litigation
In July 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005, and no decision has been issued. The ultimate outcome of these matters cannot be determined at this time.
Environmental Statutes and Regulations
General
The Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; and the
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Endangered Species Act. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2007, the Company had invested approximately $422 million in capital projects to comply with these requirements, with annual totals of $124 million, $46 million, and $45 million for 2007, 2006, and 2005, respectively. The Company expects that capital expenditures to assure compliance with existing and new statutes and regulations will be an additional $317 million, $301 million, and $134 million for 2008, 2009, and 2010, respectively. The Company’s compliance strategy is impacted by changes to existing environmental laws, statutes, and regulations, the cost, availability, and existing inventory of emission allowances, and the Company’s fuel mix. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY - “Capital Requirements and Contractual Obligations” herein.
The Florida Legislature has adopted legislation that allows a utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. The legislation is discussed in Note 3 to the financial statements under “Retail Regulatory Matters - Environmental Cost Recovery.” Substantially all of the costs for the Clean Air Act and other new environmental legislation discussed below are expected to be recovered through the environmental cost recovery clause.
Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company. New environmental legislation or regulations, or changes to existing statutes or regulations, could affect many areas of the Company’s operations; however, the full impact of any such changes cannot be determined at this time.
Air Quality
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2007, the Company had spent approximately $252 million in reducing sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been announced and are currently being installed at several plants to further reduce SO2, NOx, and mercury emissions, maintain compliance with existing regulations, and meet new requirements.
In 2004, the EPA designated nonattainment areas under an eight-hour ozone standard. No area within the Company’s service area was designated as nonattainment under the eight-hour ozone standard. Macon, Georgia, where Plant Scherer is located, was designed as nonattainment under the eight-hour ozone standard. On June 20, 2007, the EPA proposed additional revisions to the current eight-hour ozone standard which, if enacted, could result in designation of new nonattainment areas within the Company’s service territory. The EPA has requested comment and is expected to publish final revisions to the standard in 2008. The impact of this decision, if any, cannot be determined at this time and will depend on subsequent legal action and/or future nonattainment designations and state regulatory plans.
During 2005, the EPA’s fine particulate matter nonattainment designations became effective for several areas within Georgia. State plans for addressing the nonattainment designations under the existing standard are required by April 2008 and could require further reductions in SO2 and NOx emissions from power plants including plants owned in part by the Company. In September 2006, the EPA published a final rule which increased the stringency of the 24-hour average fine particulate matter air quality standard. No area within the Company’s service territory has been designated as nonattainment within that standard.
The EPA issued the final Clean Air Interstate Rule (CAIR) in March 2005. This cap-and-trade rule addresses power plant SO2 and NOx emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including Florida, Georgia, and Mississippi, are subject to the requirements of the rule. The rule calls for additional reductions of NOx and/or SO2 to be achieved in two phases, 2009/2010 and 2015. The State of Florida has an EPA-approved plan to implement this rule. These reductions will be accomplished by the installation of additional emission controls at the Company’s coal-fired facilities and/or by the purchase of emission allowances from a cap-and-trade program. The State of Georgia implemented the CAIR, and in June 2007, approved a “multi-pollutant rule” that will require plant specific emission controls on all but the smallest generating units in Georgia according to a schedule set forth in the rule. The rule is designed to ensure reductions in emissions of SO2 and NOx, and mercury in Georgia.
The Clean Air Visibility Rule (CAVR), formerly called the Regional Haze Rule, was finalized in July 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves (1) the application of Best Available Retrofit Technology (BART) to certain sources built between 1962 and 1977, and (2) the application of
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any additional emissions reductions which may be deemed necessary for each designated area to achieve reasonable progress by 2018 toward the natural conditions goal. Thereafter, for each 10-year planning period, additional emissions reductions will be required to continue to demonstrate reasonable progress in each area during that period. For power plants, the CAVR allows states to determine that the CAIR satisfies BART requirements for SO2 and NOx. Extensive studies were performed for each of the Company’s affected units to demonstrate that additional particulate matter controls are not necessary under BART. Additional analyses will be required for one of the Company’s plants in Florida. States are currently completing implementation plans that contain strategies for BART and any other measures required to achieve the first phase of reasonable progress.
The impacts of the eight-hour ozone and the fine particulate matter nonattainment designations, and the CAVR on the Company will depend on the development and implementation of rules at the state level. Therefore, the full effects of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO2 and NOx emission controls within the next several years to assure continued compliance with applicable air quality requirements.
In March 2005, the EPA published the final Clean Air Mercury Rule (CAMR), a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emission allowance trading market. The final CAMR was challenged in the U.S. Court of Appeals for the District of Columbia Circuit. The petitioners alleged that the EPA was not authorized to establish a cap-and-trade program for mercury emissions and instead the EPA must establish maximum achievable control technology standards for coal-fired electric utility steam generating units. On February 8, 2008, the court issued its ruling and vacated the CAMR. The Company’s overall environmental compliance strategy relies primarily on a combination of SO2 and NOx controls to reduce mercury emissions. Any significant changes in the strategy will depend on the outcome of any appeals and/or future federal and state rulemakings. Future rulemakings could require emission reductions more stringent than required by the CAMR.
Water Quality
In July 2004, the EPA published its final technology-based regulations under the Clean Water Act for the purpose of reducing impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures. The rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants. On January 25, 2007, the U.S. Court of Appeals for the Second Circuit overturned and remanded several provisions of the rule to the EPA for revisions. Among other things, the court rejected the EPA’s use of “cost-benefit” analysis and suggested some ways to incorporate cost considerations. The full impact of these regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by the Florida Department of Environmental Protection (FDEP) and, therefore, cannot be determined at this time.
Environmental Remediation
The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and release of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. During the second quarter 2007, the Company increased its estimated liability for environmental remediation projects by $12.8 million as a result of changes in the cost estimates to remediate substation sites. These projects have been approved by the Florida PSC for recovery through the environmental cost recovery clause; therefore, there was no impact on the Company’s net income as a result of these revised estimates. See Note 3 to the financial statements under “Environmental Matters - Environmental Remediation” for additional information.
Global Climate Issues
Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions continue to be considered in Congress. The ultimate outcome of these proposals cannot be determined at this time; however, mandatory restrictions on the Company’s greenhouse gas emissions could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
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In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. The EPA is currently developing its response to this decision. Regulatory decisions that will follow from this response may have implications for both new and existing stationary sources, such as power plants. The ultimate outcome of these rulemaking activities cannot be determined at this time; however, as with the current legislative proposals, mandatory restrictions on the Company’s greenhouse gas emissions could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and, results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
On July 13, 2007, the Governor of the State of Florida signed three executive orders addressing reduction of greenhouse gas emissions within the state, including statewide emission reduction targets beginning in 2017. Included in the orders is a directive to the Florida Secretary of Environmental Protection to develop rules adopting maximum allowable emissions levels of greenhouse gases for electric utilities, consistent with the statewide emission reduction targets, and a request to the Florida PSC to initiate rulemaking requiring utilities to produce at least 20% of their electricity from renewable sources. The impact of these orders on the Company will depend on the development, adoption, and implementation of any rules governing greenhouse gas emissions, and the ultimate outcome cannot be determined at this time.
International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. Current efforts focus on a potential successor to the Kyoto Protocol for the post-2008 through 2012 timeframe. The outcome and impact of the international negotiations cannot be determined at this time. The Company continues to evaluate its future energy and emission profiles and is participating in voluntary programs to reduce greenhouse gas emissions and to help develop and advance technology to reduce emissions.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.
In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales by the Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level.
In late June and July 2007, hearings were held in this proceeding and the presiding administrative law judge issued an initial decision on November 9, 2007 regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the Company to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates, and could also result in refunds of up to $0.8 million, plus interest. The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter.
On June 21, 2007, the FERC issued its final rule regarding market-based rate authority. The FERC generally retained its current market-based rate standards. The impact of this order and its effect on the generation dominance proceeding cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies (including the Company), Southern Power, and Southern Company Services, Inc., as agent, under the terms of which the power pool of Southern Company is operated, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct.
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In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms and Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. Southern Company filed with the FERC in November 2006 a compliance plan in connection with the order. On April 19, 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan is not expected to have a material impact on the Company’s financial statements. On November 19, 2007, Southern Company notified the FERC that the plan had been implemented and the FERC division of audits subsequently began an audit pertaining to compliance implementation and related matters, which is ongoing.
PSC Matters
Fuel Cost Recovery
The Company petitions for fuel cost recovery rates to be approved by the Florida PSC on an annual basis. At December 31, 2007 and 2006, the under recovered balance was $56.6 million and $77.5 million, respectively, primarily due to lower quantity and price for power sales in 2007 and 2006, and increased costs for coal and a higher percentage of natural gas fired generation in 2006. The Company continuously monitors the under recovered fuel cost balance in light of the inherent variability in fuel costs. If the projected fuel revenue over or under recovery exceeds 10% of the projected fuel revenue applicable for the period, the Company is required to notify the Florida PSC and indicate if an adjustment to the fuel cost recovery factor is being requested. The Company filed a notice with the Florida PSC in June 2007, and no adjustment to the factor was requested.
In November 2007, the Florida PSC approved an increase of approximately 0.4% in the fuel factor for retail customers, effective with billings beginning January 2008. The fuel factors are intended to allow the Company to recover its projected 2008 fuel and purchased power costs as well as the 2007 under recovered amounts in 2008. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changing the billing factor has no significant effect on the Company’s revenues or net income, but does impact annual cash flow. See Note 1 to the financial statements under “Revenues.”
Environmental Cost Recovery
On August 14, 2007, the Florida PSC voted to approve a stipulation among the Company, the Office of Public Counsel, and the Florida Industrial Power Users Group regarding the Company’s plan for complying with certain federal and state regulations addressing air quality. The Company’s environmental compliance plan as filed on March 29, 2007 contemplated implementation of specific projects identified in the plan from 2007 through 2018. The stipulation covers all elements of the current plan that are scheduled to be implemented in the 2007 through 2011 timeframe. The Florida PSC acknowledged that the costs associated with the Company’s CAIR/CAMR/CAVR compliance plan are clearly eligible for recovery through the environment cost recovery clause. See FINANCIAL CONDITION AND LIQUIDITY - “Capital Requirements and Contractual Obligations” herein, Note 3 to the financial statements under “Environmental Matters - Environmental Cost Recovery,” and Note 7 to the financial statements under “Construction Program” for additional information.
Storm Damage Cost Recovery
Under authority granted by the Florida PSC, the Company maintains a reserve for property damage to cover the cost of uninsured damages from major storms to its transmission and distribution facilities, generation facilities, and other property. As of December 31, 2007, the under recovered balance in the Company’s property damage reserve totaled approximately $18.6 million, which is included in current assets in the balance sheets. As of December 31, 2007, the storm-recovery costs associated with Hurricane Ivan had been fully recovered. Funds collected by the Company through its storm-recovery surcharge are now being credited to the property reserve for recovery of the storm restoration costs of $52.6 million associated with Hurricanes Dennis and Katrina that were previously charged to the reserve.
See Notes 1 and 3 to the financial statements under “Property Damage Reserve” and “Storm Damage Cost Recovery,” respectively, for additional information.
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Income Tax Matters
Bonus Depreciation
On February 13, 2008, President Bush signed the Economic Stimulus Act of 2008 (Stimulus Act) into law. The Stimulus Act includes a provision that allows 50% bonus depreciation for certain property acquired in 2008 and placed in service in 2008 or, in certain limited cases, 2009. The Company is currently assessing the financial implications of the Stimulus Act; however, the ultimate impact cannot be determined at this time.
Internal Revenue Code Section 199 Domestic Production Deduction
The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in the Internal Revenue Code of 1986, as amended (Internal Revenue Code), Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for years 2007 through 2009, and a 9% rate applicable for all years after 2009. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.
Right of Way Litigation
In September 2007, the Company and its co-defendant in the Gadsden County litigation reached a proposed settlement agreement with the plaintiffs that, if approved by the trial court, will resolve all outstanding claims against the Company in both the Gadsden County litigation and the 2001 telecommunications company litigation. On November 7, 2007, the trial court granted preliminary approval and set forth the requirements for the trial court to make its final determination on the proposed settlement. Although the final outcome of this matter cannot now be determined, if approved the settlement is not expected to have a material effect on the financial statements of the Company. See Note 3 to the financial statements under “Right of Way Litigation” for additional information.
Other Matters
In 2004, Georgia Power and the Company entered into PPAs with Florida Power & Light Company (FP&L) and Progress Energy Florida. Under the agreements, Georgia Power and the Company will provide FP&L and Progress Energy Florida with 165 megawatts and 74 megawatts, respectively, of capacity annually from the jointly owned Plant Scherer Unit 3 for the period from June 2010 through December 2015. The contracts provide for fixed capacity payments and variable energy payments based on actual energy delivered. The Florida PSC approved the contracts in 2005.
Also in 2004, Georgia Power and the Company entered into a PPA with Flint Electric Membership Corporation. Under the agreement, Georgia Power and the Company will provide Flint Electric Membership Corporation with 75 megawatts of capacity annually from the jointly owned Plant Scherer Unit 3 for the period from June 2010 through December 2019. The contract provides for fixed capacity payments and variable energy payments based on actual energy delivered.
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. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements. See Note 3 to the financial statements for information regarding material issues.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
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ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed critical accounting policies and estimates described below with the Audit Committee of Southern Company’s Board of Directors.
Electric Utility Regulation
The Company is subject to retail regulation by the Florida PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies Financial Accounting Standards Board (FASB) Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), which requires the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of SFAS No. 71 has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and postretirement benefits have less of a direct impact on the Company’s results of operations than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines and accounting principles generally accepted in the United States. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s financial statements.
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a loss is considered probable and reasonably estimable in accordance with generally accepted accounting principles. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company’s financial statements. These events or conditions include the following:
•
Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances, hazardous and solid wastes, and other environmental matters.
•
Changes in existing income tax regulations or changes in Internal Revenue Service (IRS) or state revenue department interpretations of existing regulations.
•
Identification of additional sites that require environmental remediation or the filing of other complaints in which the Company may be asserted to be a potentially responsible party.
•
Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant.
•
Resolution or progression of existing matters through the legislative process, the court systems, the IRS, the FERC, or the EPA.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
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Unbilled Revenues
Revenues related to the sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, and power delivery volume and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company’s results of operations.
New Accounting Standards
Income Taxes
On January 1, 2007, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), which requires companies to determine whether it is “more likely than not” that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. It also provides guidance on the recognition, measurement, and classification of income tax uncertainties, along with any related interest and penalties. The provisions of FIN 48 were applied to all tax positions beginning January 1, 2007. The adoption of FIN 48 did not have a material impact on the Company’s financial statements.
Pensions and Other Postretirement Plans
On December 31, 2006, the Company adopted FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS No. 158), which requires recognition of the funded status of its defined benefit postretirement plans in the balance sheets. Additionally, SFAS No. 158 will require the Company to change the measurement date for its defined benefit postretirement plan assets and obligations from September 30 to December 31 beginning with the year ending December 31, 2008. See Note 2 to the financial statements for additional information.
Fair Value Measurement
The FASB issued FASB Statement No. 157, “Fair Value Measurements” (SFAS No. 157) in September 2006. SFAS No. 157 provides guidance on how to measure fair value where it is permitted or required under other accounting pronouncements. SFAS No. 157 also requires additional disclosures about fair value measurements. The Company adopted SFAS No. 157 in its entirety on January 1, 2008, with no material effect on its financial condition or results of operations.
Fair Value Option
In February 2007, the FASB issued FASB Statement No. 159, “Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115” (SFAS No. 159). This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. The Company adopted SFAS No. 159 on January 1, 2008, with no material effect on its financial condition or results of operations.
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company’s financial condition remained stable at December 31, 2007. Net cash flow from operating activities totaled $217.0 million, $143.4 million, and $152.7 million for 2007, 2006, and 2005, respectively. The $73.6 million increase in net cash flows in 2007 was due primarily to increased cash inflows for fuel cost recovery. The $9.3 million decrease in net cash flows in 2006 was due primarily to increased payments related to income taxes and fuel. The $8.2 million increase in net cash flows in 2005 was due primarily to the recovery of Hurricane Ivan restoration costs. Net cash used for investing activities totaled $239.3 million due to gross property additions to utility plant. Funds for the Company’s property additions were provided by operating activities, capital
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2007 Annual Report
contributions, and other financing activities. Net cash provided from financing activities totaled $20.2 million in 2007, compared to $24.7 million in 2006. See the statements of cash flows for additional information.
Significant balance sheet changes in 2007 included a $97.2 million increase in common stockholder’s equity primarily due to the issuance of 800,000 shares of common stock to Southern Company, without par value, and realized proceeds of $80 million. Other significant balance sheet changes in 2007 included a net increase of $162.1 million in property, plant, and equipment, the issuance of $45 million in preference stock, and the issuance of $85 million in long-term debt, partially offset by the redemption of $41.2 million in long-term debt payable to affiliated trusts.
The Company’s ratio of common equity to total capitalization, including short-term debt, was 45.3% in 2007, 42.1% in 2006, and 43.0% in 2005. See Note 6 to the financial statements for additional information.
The Company has received investment grade ratings from the major rating agencies with respect to its debt and preference stock.
Sources of Capital
The Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, securities issuances, term loans, and short-term indebtedness. However, the type and timing of any future financings, if needed, will depend on market conditions, regulatory approval, and other factors.
Security issuances are subject to regulatory approval by the Florida PSC pursuant to its rules and regulations. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the Florida PSC, as well as the amounts, if any, registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.
The Company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company.
To meet short-term cash needs and contingencies, the Company has various internal and external sources of liquidity. At the beginning of 2008, the Company had approximately $5.3 million of cash and cash equivalents, along with $125 million of unused committed lines of credit with banks to meet its short-term cash needs. These bank credit arrangements will expire during 2008. The Company plans to renew these lines of credit during 2008. In addition, the Company has substantial cash flow from operating activities and access to the capital markets including commercial paper programs to meet liquidity needs. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.
The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other traditional operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other traditional operating company. There is no cross affiliate credit support. At December 31, 2007, the Company had $40.8 million of commercial paper outstanding. In addition, the Company had $3.8 million in notes payable outstanding to General Electric.
Financing Activities
During 2007, the Company issued $85 million of senior notes and $45 million of preference stock. The proceeds were used to repay a portion of short-term indebtedness and for other general corporate purposes, including the Company’s continuous construction program.
On January 19, 2007, the Company issued to Southern Company 800,000 shares of the Company’s common stock, without par value, and realized proceeds of $80 million. The proceeds were used to repay a portion of the Company’s short-term indebtedness and for other general corporate purposes.
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.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
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There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- or Baa3, or below. Generally, collateral may be provided for by a Southern Company guaranty, letter of credit, or cash. These contracts are primarily for physical electricity purchases and sales. At December 31, 2007, the maximum potential collateral requirements at a BBB- or Baa3 rating were approximately $23 million. The maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $46 million.
The Company, along with all members of the Southern Company power pool, is party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade for Alabama Power and/or Georgia Power. These agreements are primarily for natural gas and power price risk management activities. At December 31, 2007, the Company’s total exposure to these types of agreements was approximately $15 million.
Market Price Risk
Due to cost-based rate regulation, the Company has limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. Company policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including but not limited to market valuation, value at risk, stress testing, and sensitivity analysis.
To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts for natural gas purchases. The Company has implemented a fuel-hedging program with the approval of the Florida PSC.
Of the Company’s remaining $144.6 million of variable interest rate exposure, approximately $141 million relates to tax-exempt auction rate pollution control bonds. Recent weakness in the auction markets has resulted in higher interest rates. The Company has sent notice of conversion related to $37 million of these auction rate securities to alternative interest rate determination methods and plans to remarket all remaining auction rate securities in a timely manner. None of the securities are insured or backed by letters of credit that would require approval of a guarantor or security provider. It is not expected that the higher rates as a result of the weakness in the auction markets will be material.
The weighted average interest rate on $144.6 million variable long-term debt that has not been hedged at January 1, 2008 was 4.50%. If the Company sustained a 100 basis point change in interest rates for all variable rate long-term debt, the change would affect annualized interest expense by approximately $1.4 million at January 1, 2008. See Notes 1 and 6 to the financial statements under “Financial Instruments” for additional information.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2007 Annual Report
The changes in fair value of energy-related derivative contracts and year-end valuations were as follows at December 31:
(a)
Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
Unrealized gains and losses from mark-to-market adjustments on derivative contracts related to the Company’s fuel hedging programs are recorded as regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are recovered through the Company’s fuel cost recovery clause. Gains and losses on derivative contracts that are not designated as hedges are recognized in the statements of income as incurred. At December 31, 2007, the fair value gains/(losses) of energy-related derivative contracts were reflected in the financial statements as follows:
Unrealized (losses) recognized in income were not material in any year presented.
The Company is exposed to market price risk in the event of nonperformance by counterparties to the derivative energy contracts. The Company’s policy is to enter into agreements with counterparties that have investment grade credit ratings by Moody’s and Standard & Poor’s or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. See Notes 1 and 6 to the financial statements under “Financial Instruments” for additional information.
Capital Requirements and Contractual Obligations
The construction program of the Company is currently estimated to be $410 million in 2008, $426 million in 2009, and $245 million in 2010. Environmental expenditures included in these estimated amounts are $317 million in 2008, $301 million in 2009, and $134 million in 2010. Actual construction costs may vary from these estimates because of changes in such factors as: business conditions; environmental statutes and regulations; FERC rules and regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
The Company does not have any new generating capacity under construction. Construction of new transmission and distribution facilities and capital improvements, including those needed to meet environmental standards for the Company’s existing generation, transmission, and distribution facilities, is ongoing.
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The Company has entered into two PPAs, one of which is with Southern Power, for a total of approximately 487 megawatts annually from June 2009 through May 2014. The PPAs were the result of a competitive request for proposals process initiated by the Company in January 2006 to address the anticipated need for additional capacity beginning in 2009. On May 11, 2007, the Florida PSC issued an order approving both PPAs for purposes of cost recovery through the Company’s purchased power capacity clause. The PPA with Southern Power was approved by the FERC on July 13, 2007.
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 FERC and the Florida PSC.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preference stock dividends, leases, and other purchase commitments are as follows. See Notes 1, 6, and 7 to the financial statements for additional information.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
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Contractual Obligations
(a)
All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2008, as reflected in the statements of capitalization.
(b)
For additional information, see Notes 1 and 6 to the financial statements.
(c)
Preference stock does not mature; therefore, amounts are provided for the next five years only.
(d)
The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for the last three years were $270 million, $260 million, and $250 million, respectively.
(e)
The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures. At December 31, 2007, significant purchase commitments were outstanding in connection with the construction program.
(f)
As part of the Company’s program to reduce sulfur dioxide emissions from certain of its coal plants, the Company is constructing certain equipment and has entered into various long-term commitments for the procurement of limestone to be used in such equipment.
(g)
Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2007.
(h)
Long-term service agreements include price escalation based on inflation indices.
(i)
The Company forecasts postretirement trust contributions over a three-year period. No contributions related to the Company’s pension trust are currently expected during this period. See Note 2 to the financial statements for additional information related to the pension and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.
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Cautionary Statement Regarding Forward-Looking Statements
The Company’s 2007 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail rates, storm damage cost recovery and repairs, fuel cost recovery, environmental regulations and expenditures, earnings growth, access to sources of capital, projections for postretirement benefit trust contributions, financing activities, completion of construction projects, impacts of adoption of new accounting rules, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
•
the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, or particulate matter and other substances, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
•
current and future litigation, regulatory investigations, proceedings or inquiries, including FERC matters and the EPA civil actions against the Company;
•
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
•
variations in demand for electricity, including those relating to weather, the general economy, population, and business growth (and declines), and the effects of energy conservation measures;
•
available sources and costs of fuel;
•
effects of inflation;
•
ability to control costs;
•
investment performance of the Company’s employee benefit plans;
•
advances in technology;
•
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and storm restoration cost recovery;
•
internal restructuring or other restructuring options that may be pursued;
•
potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;
•
the ability of counterparties of the Company to make payments as and when due;
•
the ability to obtain new short- and long-term contracts with neighboring utilities;
•
the direct or indirect effect on the Company’s business resulting from terrorist incidents and the threat of terrorist incidents;
•
interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company’s credit ratings;
•
the ability of the Company to obtain additional generating capacity at competitive prices;
•
catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as an avian influenza, or other similar occurrences;
•
the direct or indirect effects on the Company’s business resulting from incidents similar to the August 2003 power outage in the Northeast;
•
the effect of accounting pronouncements issued periodically by standard setting bodies; and
•
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
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STATEMENTS OF INCOME
For the Years Ended December 31, 2007, 2006, and 2005
Gulf Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2007, 2006, and 2005
Gulf Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2007 and 2006
Gulf Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2007 and 2006
Gulf Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF CAPITALIZATION
At December 31, 2007 and 2006
Gulf Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2007, 2006, and 2005
Gulf Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2007, 2006, and 2005
Gulf Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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NOTES TO FINANCIAL STATEMENTS
Gulf Power Company 2007 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Gulf Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies, Alabama Power, Georgia Power, the Company, and Mississippi Power, are vertically integrated utilities providing electric service in four Southeastern states. The Company provides retail service to customers in northwest Florida and to wholesale customers in the Southeast. Southern Power constructs, acquires, and manages generation assets and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and the subsidiary companies. SouthernLINC Wireless provides digital wireless communications services to the traditional operating companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy-related businesses. The investments in synthetic fuels ended on December 31, 2007. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants.
The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable interest entities where the Company is not the primary beneficiary.
The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC) and the Florida Public Service Commission (PSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from those estimates.
Reclassifications
Certain prior years’ data presented in the financial statements have been reclassified to conform to current year presentation. These reclassifications had no effect on total assets, net income, or cash flows. For presentation purposes, the balance sheets and the statements of cash flows have been modified to combine “Long-term Debt Payable to Affiliate Trusts” into “Long-term Debt.” Correspondingly, the statements of income were modified to report “Interest expense to affiliate trusts” together with “Interest expense, net of amounts capitalized.”
Affiliate Transactions
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, purchasing, accounting and statistical analysis, finance and treasury, tax, information resources, marketing, auditing, insurance and pension administration, human resources, systems and procedures, and other services with respect to business and operations and power pool operations. Costs for these services amounted to $73 million, $59 million, and $54 million during 2007, 2006, and 2005, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.
The Company has agreements with Georgia Power and Mississippi Power under which the Company owns a portion of Plant Scherer and Plant Daniel, respectively. Georgia Power operates Plant Scherer and Mississippi Power operates Plant Daniel. The Company reimbursed Georgia Power $5.1 million, $8.0 million, and $4.3 million and Mississippi Power $23.1 million, $19.7 million, and $19.5 million in 2007, 2006, and 2005, respectively, for its proportionate share of related expenses. See Note 4 and Note 7 under “Operating Leases” for additional information.
The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. However, with the hurricane damage experienced in 2005, assistance provided to aid in storm restoration, including Company labor, contract labor, and materials, caused an increase in these activities. The total amount of storm restoration provided to Mississippi Power was $11.1 million in 2005. The Company received storm restoration assistance from other Southern Company subsidiaries totaling $5.8 million in 2005. These activities were billed at cost.
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The traditional operating companies, including the Company, and Southern Power jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under “Fuel Commitments” for additional information.
In 2007, the Company purchased equipment from Georgia Power and Southern Power. The purchase price was $4.0 million and $7.9 million, respectively, and is included in property, plant and equipment in the balance sheets.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
Note:
The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
(a)
Recovered through the environmental cost recovery clause when the remediation is performed.
(b)
Recovered over the remaining life of the original issue, which may range up to 40 years.
(c)
Recorded as earned by employees and recovered as paid, generally within one year.
(d)
Asset retirement and removal liabilities are recovered, deferred charges related to income tax assets are recovered, and deferred charges related to income tax liabilities are amortized over the related property lives, which may range up to 65 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.
(e)
Fuel-hedging assets and liabilities are recognized over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, costs are recovered through the fuel cost recovery clause.
(f)
Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 under “Retirement Benefits.”
(g)
Recorded and recovered or amortized as approved by the Florida PSC.
(h)
Recorded and recovered or amortized as approved by the Florida PSC. Storm cost recovery surcharge ends in June 2009.
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In the event that a portion of the Company’s operations is no longer subject to the provisions of SFAS No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant assets, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are reflected in rates.
Revenues
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. Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract period. The Company’s retail electric rates include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. The Company continuously monitors the under recovered fuel cost balance in light of the inherent variability in fuel costs. The Company is required to notify the Florida PSC if the projected fuel revenue over or under recovery exceeds 10% of the projected fuel revenue applicable for the period and indicate if an adjustment to the fuel cost recovery factor is being requested. The Company filed a notice with the Florida PSC in June 2007 and no adjustment to the factor was requested. The Company has similar retail cost recovery clauses for energy conservation costs, purchased power capacity costs, and environmental compliance 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. Annually, the Company petitions for recovery of projected costs including any true-up amount from prior periods, and approved rates are implemented each January. In November 2007, the Florida PSC approved billing factors for 2008 intended to allow the Company to recover projected 2008 costs as well as refund or collect the 2007 over or under recovered amounts in 2008.
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.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction.
The Company’s property, plant, and equipment consisted of the following at December 31:
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred or performed.
Income and Other Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are
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presented net on the statements of income. In accordance with FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), the Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information on the effect of adopting FIN 48.
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.4% in 2007, 3.7% in 2006, and 3.8% in 2005. Depreciation studies are conducted periodically to update the composite rates. These studies are approved by the Florida PSC. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.
Asset Retirement Obligations and Other Costs of Removal
Asset retirement obligations are computed as the present value of the ultimate costs for an asset’s future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. The Company has received an order from the Florida PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations will continue to be reflected in the balance sheets as a regulatory liability.
The liability recognized to retire long-lived assets primarily relates to the Company’s combustion turbines at its Pea Ridge facility, various landfill sites, and a barge unloading dock. In connection with the adoption of FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), the Company also recorded additional asset retirement obligations (and assets) of $9.1 million, primarily related to asbestos removal, ash ponds, and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the United States Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized under FASB Statement No. 143 “Accounting for Asset Retirement Obligations” and FIN 47 and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Florida PSC, and are reflected in the balance sheets.
Details of the asset retirement obligations included in the balance sheets are as follows:
Allowance for Funds Used During Construction (AFUDC)
In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. The equity component of AFUDC is not included in calculating taxable income. For the years 2007, 2006, and 2005, the average annual AFUDC rate was 7.48%. AFUDC, net of taxes, as a percentage of net income after dividends on preferred and preference stock was 3.59%, 0.61%, and 1.97%, respectively, for 2007, 2006, and 2005.
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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.
Property Damage Reserve
The Company accrues for the cost of repairing damages from major storms and other uninsured property damages, including uninsured damages to transmission and distribution facilities, generation facilities, and other property. The cost of such damages is charged to the reserve. The Florida PSC approved annual accrual to the property damage reserve is $3.5 million, with a target level for the reserve between $25.1 million and $36.0 million. The Florida PSC also authorized the Company to make additional accruals above the $3.5 million at the Company’s discretion. The Company accrued total expenses of $3.5 million in 2007, $6.5 million in 2006, and $9.5 million in 2005. At December 31, 2007, the unrecovered balance in the property damage reserve totaled approximately $18.6 million. See Note 3 under “Retail Regulatory Matters - Storm Damage Cost Recovery” for additional information regarding the surcharge mechanism approved by the Florida PSC to replenish these reserves.
Injuries and Damages Reserve
The Company is subject to claims and suits arising in the ordinary course of business. As permitted by the Florida PSC, the Company accrues for the uninsured costs of injuries and damages by charges to income amounting to $1.6 million annually. The Florida PSC has also given the Company the flexibility to increase its annual accrual above $1.6 million to the extent the balance in the reserve does not exceed $2 million and to defer expense recognition of liabilities greater than the balance in the reserve. The cost of settling claims is charged to the reserve. The injuries and damages reserve was $2.2 million and $2.0 million at December 31, 2007 and 2006, respectively, and is included in Current Liabilities in the balance sheets. Liabilities in excess of the reserve balance of $0.8 million and $1.7 million at December 31, 2007 and 2006, respectively, are included in Deferred Credits and Other Liabilities in the balance sheets. Corresponding regulatory assets of $0.8 million and $1.6 million at December 31, 2007 and 2006, respectively, are included in Current Assets in the balance sheets. At December 31, 2007 and 2006, respectively, none and $0.1 million are included in Deferred Charges and Other Assets in the balance sheets.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
Fuel Inventory
Fuel inventory includes the average costs of oil, coal, natural gas, and emission allowances. Fuel is charged to inventory when purchased and then expensed as used. Emission allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.
Stock Options
Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. Prior to January 1, 2006, the Company accounted for options granted in accordance with Accounting
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Principles Board Opinion No. 25; thus, no compensation expense was recognized because the exercise price of all options granted equaled the fair market value on the date of the grant.
Effective January 1, 2006, the Company adopted the fair value recognition provisions of FASB Statement No. 123(R), “Share-Based Payment” (SFAS No. 123(R)), using the modified prospective method. Under that method, compensation cost for the years ended December 31, 2007 and 2006 was recognized as the requisite service was rendered and included: (a) compensation cost for the portion of share-based awards granted prior to and that were outstanding as of January 1, 2006, for which the requisite service had not been rendered, based on the grant-date fair value of those awards as calculated in accordance with the original provisions of FASB Statement No. 123, “Accounting for Stock-Based Compensation” and (b) compensation cost for all share-based awards granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123(R). Results for prior periods have not been restated.
The compensation cost and tax benefit related to the grant and exercise of Southern Company stock options to the Company’s employees are recognized in the Company’s financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company.
For the Company, the adoption of SFAS No. 123(R) has resulted in a reduction in earnings before income taxes and net income of $1.1 million and $0.7 million, respectively, for the year ended December 31, 2007 and $1.0 million and $0.6 million, respectively, for the year ended December 31, 2006. Additionally, SFAS No. 123(R) requires the gross excess tax benefit from stock option exercises to be reclassified as a financing cash flow as opposed to an operating cash flow; the reduction in operating cash flows and the increase in financing cash flows for the years ended December 31, 2007 and 2006 was $0.8 million and $0.4 million, respectively.
For the year ended December 31, 2005, prior to the adoption of SFAS No. 123(R), the pro forma impact on net income of fair-value accounting for options granted was as follows:
Because historical forfeitures have been insignificant and are expected to remain insignificant, no forfeitures were assumed in the calculation of compensation expense; rather they are recognized when they occur.
The estimated fair values of stock options granted in 2007, 2006, and 2005 were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company’s stock over a period equal to the expected term. The Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted:
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities and are measured at fair value. Substantially all of the Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are exempt from fair value accounting requirements and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the Florida PSC-approved hedging program. This results in the deferral of related gains and losses in other comprehensive income or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net
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income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income.
The Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk.
Other financial instruments for which the carrying amounts did not equal fair values at December 31 were as follows:
The fair values were based on either closing market prices or closing prices of comparable instruments.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income and changes in the fair value of qualifying cash flow hedges, and prior to the adoption of SFAS No.158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS No. 158) the minimum pension liability, less income taxes and reclassifications for amounts included in net income.
Variable Interest Entities
The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. The Company had established certain wholly-owned trusts to issue preferred securities. The Company is not considered the primary beneficiary of the trusts. Therefore, the investments in these trusts were reflected as Other Investments for the Company, and the related loans from the trusts were included in Long-term Debt in the balance sheets. In November 2007, the Company redeemed $41.2 million of its Series E Junior Subordinated Notes and the related trust preferred and common securities of Gulf Power Capital Trust IV. As of December 31, 2007, the Company no longer had any outstanding trust preferred securities. See Note 6 under “Long-Term Debt Payable to Affiliated Trusts” for additional information.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the plan are expected for the year ending December 31, 2008. The Company also provides a defined benefit pension plan for a selected group of management and highly compensated employees. Benefits under this non-qualified plan 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 related trusts to the extent required by the FERC. For the year ending December 31, 2008, postretirement trust contributions are expected to total approximately $60,000.
The measurement date for plan assets and obligations is September 30 for each year presented. Pursuant to SFAS No. 158, Southern Company will be required to change the measurement date for its defined benefit postretirement plans from September 30 to December 31 beginning with the year ending December 31, 2008.
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Pension Plans
The total accumulated benefit obligation for the pension plans was $230 million in 2007 and $242 million in 2006. Changes during the year in the projected benefit obligations and fair value of plan assets were as follows:
At December 31, 2007, the projected benefit obligations for the qualified and non-qualified pension plans were $238.6 million and $13.2 million, respectively. All plan assets are related to the qualified pension plan.
Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk. The actual composition of the Company’s pension plan assets as of the end of the year, along with the targeted mix of assets, is presented below:
Amounts recognized in the balance sheets related to the Company’s pension plans consist of the following:
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Presented below are the amounts included in regulatory assets and regulatory liabilities at December 31, 2007 and 2006 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 2008.
The changes in the balances of regulatory assets and regulatory liabilities related to the defined benefit pension plans for the year ended December 31, 2007 are presented in the following table:
Components of net periodic pension cost (income) were as follows:
Net periodic pension cost (income) is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-
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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, 2007, estimated benefit payments were as follows:
Other Postretirement Benefits
Changes during the year in the accumulated postretirement benefit obligations (APBO) and in the fair value of plan assets were as follows:
Other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk. The actual composition of the Company’s other postretirement benefit plan assets as of the end of the year, along with the targeted mix of assets, is presented below:
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Amounts recognized in the balance sheets related to the Company’s other postretirement benefit plans consist of the following:
Presented below are the amounts included in regulatory assets at December 31, 2007 and 2006 related to the other postretirement benefit plans that have not yet been recognized in net periodic postretirement benefit cost along with the estimated amortization of such amounts for the next fiscal year.
The change in the balance of regulatory assets related to the other postretirement benefit plans for the year ended December 31, 2007 is presented in the following table:
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Components of the other postretirement benefit plans’ net periodic cost were as follows:
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced the Company’s expenses for the years ended December 31, 2007, 2006, and 2005 by approximately $1.5 million, $1.7 million, and $1.1 million, respectively, and is expected to have a similar impact on future expenses.
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the postretirement plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows:
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 2004 for the 2005 plan year using a discount rate of 5.75%.
The Company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.
An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 9.75% for 2008, decreasing gradually to 5.25% through the year 2015 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2007 as follows:
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Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution up to 6% of an employee’s base salary. Prior to November 2006, the Company matched employee contributions at a rate of 75% up to 6% of the employee’s base salary. Total matching contributions made to the plan for 2007, 2006, and 2005 were $3.5 million, $3.0 million, and $2.9 million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements.
Environmental Matters
New Source Review Actions
In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama after Alabama Power was dismissed from the original action. In these lawsuits, the EPA alleged that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation relating to the Company’s Plant Crist and a unit partially owned by the Company at Plant Scherer. See Note 4 to the financial statements for information on the Company’s ownership interest in Plant Scherer Unit 3. In early 2000, the EPA filed a motion to amend its complaint to add the allegations in the notices of violation and to add the Company as a defendant. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not refiled. The action against Georgia Power has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case.
The plaintiffs appealed the district court’s decision to the U.S. Court of Appeals for the Eleventh Circuit, and the appeal was stayed by the Appeals Court pending the U.S. Supreme Court’s decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke Energy case in April 2007. On October 5, 2007, the U.S. District Court for the Northern District of Alabama issued an order in the Alabama Power case indicating a willingness to re-evaluate its previous decision in light of the Supreme Court’s Duke Energy opinion. On December 21, 2007, the Eleventh Circuit vacated the district court’s decision in the Alabama Power case and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court’s decision in Duke Energy case.
The Company believes it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in this matter could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
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Carbon Dioxide Litigation
In July 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and no decision has been issued. The ultimate outcome of these matters cannot be determined at this time.
Environmental Remediation
The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. The Company received authority from the Florida PSC to recover approved environmental compliance costs through the environmental cost recovery clause. The Florida PSC reviews costs and adjusts rates up or down annually.
At December 31, 2007 and 2006, the Company’s liability for the estimated costs of environmental remediation projects for known sites was $66.9 million and $57.2 million, respectively. During the second quarter 2007, the Company increased its estimated liability for environmental remediation projects by $12.8 million as a result of changes in the cost estimates to remediate substation sites. These estimated costs relate to new regulations and more stringent site closure criteria by the Florida Department of Environmental Protection (FDEP) for impacts to groundwater from herbicide applications at the Company’s substations. The schedule for completion of the remediation projects will be subject to FDEP approval. These projects have been approved by the Florida PSC for recovery through the environmental cost recovery clause. Therefore, the Company has recorded $1.8 million in Current Assets and Current Liabilities and $65.1 million in Deferred Charges and Other Assets and Deferred Credits and Other Liabilities representing the future recoverability of these costs.
The final outcome of these matters cannot now be determined. However, based on the currently known conditions at these sites and the nature and extent of the Company’s activities relating to these sites, management does not believe that the Company’s additional liabilities, if any, at these sites would be material to the financial statements.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.
In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales by the Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level.
In late June and July 2007, hearings were held in this proceeding and the presiding administrative law judge issued an initial decision on November 9, 2007 regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the Company and Southern Power to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates, and could also result in refunds of up to $0.8 million, plus interest. The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter.
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On June 21, 2007, the FERC issued its final rule regarding market-based rate authority. The FERC generally retained its current market-based rate standards. The impact of this order and its effect on the generation dominance proceeding cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet is operated under the Intercompany Interchange Contract (IIC), as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies (including the Company), Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct.
In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms and Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. Southern Company filed with the FERC in November 2006 a compliance plan in connection with the order. On April 19, 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan is not expected to have a material impact on the Company’s financial statements. On November 19, 2007 Southern Company notified the FERC that the plan had been implemented and the FERC division of audits subsequently began an audit pertaining to compliance implementation and related matters, which is ongoing.
Right of Way Litigation
Southern Company and certain of its subsidiaries, including the Company, Mississippi Power, and Southern Telecom, Inc. (a subsidiary of SouthernLINC Wireless), have been named as defendants in numerous lawsuits brought by landowners since 2001. The plaintiffs’ lawsuits claim that defendants may not use, or sublease to third parties, some or all of the fiber optic communications lines on the rights of way that cross the plaintiffs’ properties, and that such actions exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment, and seek compensatory and punitive damages and injunctive relief. The Company’s management believes that it has complied with applicable laws and that the plaintiffs’ claims are without merit.
In November 2003, the Second Circuit Court in Gadsden County, Florida, ruled in favor of the plaintiffs on their motion for partial summary judgment concerning liability in one such lawsuit brought by landowners regarding the installation and use of fiber optic cable over the Company rights of way located on the landowners’ property. Subsequently, the plaintiffs sought to amend their complaint and asked the court to enter a final declaratory judgment and to enter an order enjoining the Company from allowing expanded general telecommunications use of the fiber optic cables that are the subject of this litigation. In January 2005, the trial court granted in part the plaintiffs’ motion to amend their complaint and denied the requested declaratory and injunctive relief. In November 2005, the trial court ruled in favor of the plaintiffs and against the Company on their respective motions for partial summary judgment. In that same order, the trial court also denied the Company’s motion to dismiss certain claims. The Company filed an appeal to the Florida First District Court of Appeals in December 2005. In October 2006, the Florida First District Court of Appeal issued an order dismissing the Company’s December 2005 appeal on the basis that the trial court’s order was a non-final order and therefore not subject to review on appeal at this time. The case was returned to the trial court for further proceedings. The parties reached agreement on a proposed settlement plan that was subject to approval by the trial court. On November 7, 2007, the trial court granted preliminary approval and set forth the requirements for the trial court to make its final determination on the proposed settlement. Although the final outcome of this matter cannot now be determined, if approved the settlement is not expected to have a material effect on the financial statements of the Company.
In addition, in late 2001, certain subsidiaries of Southern Company, including the Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Telecom, Inc. (a subsidiary of SouthernLINC Wireless), were named as defendants in a lawsuit brought by a telecommunications company that uses certain of the defendants’ rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. The Company believes that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation
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discussed above. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. An adverse outcome in this matter, combined with an adverse outcome against the telecommunications company in one or more of the right of way lawsuits, could result in substantial judgments; however, the final outcome of these matters cannot now be determined.
Property Tax Dispute
The Monroe County Board of Tax Assessors (Monroe Board) had issued assessments reflecting substantial increases in the ad valorem tax valuation of the Company’s 6.25% ownership interest in Plant Scherer, which is located in Monroe County, Georgia (Monroe County) for tax years 2003 through 2007. Georgia Power and the Company pursued administrative appeals in Monroe County and filed notices of arbitration for all disputed years. The outcome of the litigation is discussed below.
In November 2004, Georgia Power filed suit, on its behalf, against the Monroe Board in the Superior Court of Monroe County. The Company requested injunctive relief prohibiting Monroe County and the Monroe Board from unlawfully changing the value of Plant Scherer and ultimately collecting additional ad valorem taxes from Georgia Power. In December 2005, the court granted Monroe County’s motion for summary judgment. Georgia Power filed an appeal of the Superior Court’s decision to the Georgia Supreme Court.
On March 30, 2007, the Georgia Court of Appeals reversed the trial court and ruled that the Monroe Board had exceeded its legal authority and remanded the case for entry of an injunction prohibiting the Monroe Board from collecting taxes based on its independent valuation of Plant Scherer. On July 16, 2007, the Georgia Supreme Court agreed to hear the Monroe Board’s requested review of this decision. On January 8, 2008, the Georgia Supreme Court upheld the appeals court decision preventing Monroe County from reassessing the fair market value of Plant Scherer as filed in the tax years 2003, 2004, 2005, 2006, and 2007. This litigation is now concluded.
Retail Regulatory Matters
Environmental Cost Recovery
The Florida Legislature adopted legislation for an environmental cost recovery clause, which allows an electric utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Such environmental costs include operation and maintenance expense, emission allowance expense, depreciation, and a return on invested capital. This legislation also allows recovery of costs incurred as a result of an agreement between the Company and the FDEP for the purpose of ensuring compliance with ozone ambient air quality standards adopted by the EPA. On August 14, 2007, the Florida PSC voted to approve a stipulation among the Company, the Office of Public Counsel, and the Florida Industrial Power Users Group regarding the Company’s plan for complying with certain federal and state regulations addressing air quality. The Company’s environmental compliance plan as filed on March 29, 2007 contemplates implementation of specific projects identified in the plan from 2007 through 2018. The stipulation covers all elements of the current plan that are scheduled to be implemented in the 2007 through 2011 timeframe. The Florida PSC acknowledged that the costs associated with the Company’s Clean Air Interstate Rule/Clean Air Mercury Rule/Clean Air Visibility Rule compliance plan are eligible for recovery through the environmental cost recovery clause. During 2007, 2006, and 2005, the Company recorded environmental cost recovery clause revenues of $43.6 million, $40.9 million, and $26.3 million, respectively. Annually, the Company seeks recovery of projected costs including any true-up amounts from prior periods. At December 31, 2007, the over recovered balance was $1.6 million primarily due to operations and maintenance expenses being less than anticipated.
Storm Damage Cost Recovery
Under authority granted by the Florida PSC, the Company maintains a reserve for property damage to cover the cost of uninsured damages from major storms to its transmission and distribution facilities, generation facilities, and other property.
Hurricanes Dennis and Katrina hit the Gulf Coast of Florida in July 2005 and August 2005, respectively, damaging portions of the Company’s service area. In September 2004, Hurricane Ivan hit the Gulf Coast of Florida, causing substantial damage within the Company’s service area. In 2005, the Florida PSC issued an order that approved a stipulation and settlement between the Company and several consumer groups and thereby authorized the recovery of the Company’s storm damage costs related to Hurricane Ivan through a two-year surcharge that began in April 2005.
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In July 2006, the Florida PSC issued an order (2006 Order) approving a stipulation and settlement between the Company and several consumer groups that resolved all matters relating to the Company’s request for recovery of incurred costs for storm-recovery activities and the replenishment of the Company’s property damage reserve. The 2006 Order provided for an extension of the storm-recovery surcharge then being collected by the Company for an additional 27 months, expiring in June 2009.
Pursuant to the 2006 Order, the funds resulting from the extension of the surcharge were first credited to the unrecovered balance of storm-recovery costs associated with Hurricane Ivan until these costs were fully recovered. The funds are now being credited to the property reserve for recovery of the storm restoration costs of $52.6 million associated with Hurricanes Dennis and Katrina that were previously charged to the reserve. Should revenues collected by the Company through the extension of the storm-recovery surcharge exceed the storm restoration costs associated with Hurricanes Dennis and Katrina, the excess revenues will be credited to the reserve.
The annual accrual to the reserve of $3.5 million and the Company’s limited discretionary authority to make additional accruals to the reserve will continue as previously approved by the Florida PSC. The Company made discretionary accruals to the reserve of $3 million and $6 million in 2006 and 2005, respectively. The Company made no discretionary accruals to the reserve in 2007.
According to the 2006 Order, in the case of future storms, if the Company incurs cumulative costs for storm-recovery activities in excess of $10 million during any calendar year, the Company will be permitted to file a streamlined formal request for an interim surcharge. Any interim surcharge would provide for the recovery, subject to refund, of up to 80% of the claimed costs for storm-recovery activities. The Company would then petition the Florida PSC for full recovery through a final or non-interim surcharge or other cost recovery mechanism.
See Note 1 under “Property Damage Reserve” for additional information.
4. JOINT OWNERSHIP AGREEMENTS
The Company and Mississippi Power jointly own Plant Daniel Units 1 and 2, which together represent capacity of 1,000 megawatts (MW). Plant Daniel is a generating plant located in Jackson County, Mississippi. In accordance with the operating agreement, Mississippi Power acts as the Company’s agent with respect to the construction, operation, and maintenance of these units.
The Company and Georgia Power jointly own the 818 MW capacity Plant Scherer Unit 3. Plant Scherer is a generating plant located near Forsyth, Georgia. In accordance with the operating agreement, Georgia Power acts as the Company’s agent with respect to the construction, operation, and maintenance of the unit.
The Company’s pro rata share of expenses related to both plants is included in the corresponding operating expense accounts in the statements of income.
At December 31, 2007, the Company’s percentage ownership and its investment in these jointly owned facilities were as follows:
(a)
Includes net plant acquisition adjustment of $3.6 million.
5. INCOME TAXES
Southern Company files a consolidated federal income tax return and combined State of Mississippi and State of Georgia income tax returns. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. In accordance with Internal Revenue Service (IRS) regulations, each company is jointly and severally liable for the tax liability.
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Current and Deferred Income Taxes
Details of income tax provisions are as follows:
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:
At December 31, 2007, the tax-related regulatory assets to be recovered from customers were $17.8 million. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized allowance for funds used during construction. At December 31, 2007, the tax-related regulatory liabilities to be credited to customers were $15.3 million. These liabilities are attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized investment tax credits.
In accordance with regulatory requirements, deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $1.7 million in 2007, $1.8 million in 2006, and $1.9 million in 2005. At December 31, 2007, all investment tax credits available to reduce federal income taxes payable had been utilized.
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Effective Tax Rate
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to United States production activities as defined in Internal Revenue Code Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for years 2007 through 2009, and a 9% rate applicable for all years after 2009. The increase from 3% in 2006 to 6% in 2007 was one of several factors that increased the Company’s 2007 deduction by $4 million over the 2006 deduction. The resulting additional tax benefit was over $1 million.
Unrecognized Tax Benefits
On January 1, 2007, the Company adopted FIN 48, which requires companies to determine whether it is “more likely than not” that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. It also provides guidance on the recognition, measurement, and classification of income tax uncertainties, along with any related interest and penalties.
Prior to the adoption of FIN 48, the Company had unrecognized tax benefits which were previously accrued under Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies” of approximately $0.2 million. The total $0.2 million in unrecognized tax benefits would impact the Company’s effective tax rate if recognized. For 2007, the total amount of unrecognized tax benefits increased by $0.7 million, resulting in a balance of $0.9 million as of December 31, 2007.
Changes during the year in unrecognized tax benefits were as follows:
Impact on the Company’s effective tax rate, if recognized, is as follows:
Accrued interest for unrecognized tax benefits:
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The Company classifies interest on tax uncertainties as interest expense. Net interest accrued for the year ended December 31, 2007 was $58 thousand. The Company did not accrue any penalties on uncertain tax positions.
The IRS has audited and closed all tax returns prior to 2004. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2002.
It is reasonably possible that the amount of the unrecognized benefit with respect to certain of the Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The possible settlement of the production activities deduction methodology and/or the conclusion or settlement of federal or state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
6. FINANCING
Long-Term Debt Payable to Affiliated Trusts
The Company has formed certain wholly owned trust subsidiaries for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to the Company through the issuance of junior subordinated notes which constitute substantially all of the assets of these trusts and are reflected in the balance sheets as Long-term Debt. 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 trusts’ payment obligations with respect to these securities. During 2007, the Company redeemed its last remaining series, which totaled $41.2 million. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities.
Outstanding Classes of Capital Stock
The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized. The Company’s preferred stock and Class A preferred stock, without preference between classes, rank senior to the Company’s preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. No shares of preferred stock or Class A preferred stock were outstanding at December 31, 2007. The Company’s preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. Certain series of the preference stock are subject to redemption at the option of the Company on or after a specified date (typically 5 or 10 years after the date of issuance) at a redemption price equal to 100% of the liquidation amount of the preference stock. In addition, one series of the preference stock may be redeemed earlier at a redemption price equal to 100% of the liquidation amount plus a make-whole premium based on the present value of the liquidation amount and future dividends.
On January 19, 2007, the Company issued to Southern Company 800,000 shares of the Company’s common stock, without par value, and realized proceeds of $80 million. The proceeds were used to repay a portion of the Company’s short-term indebtedness and for other general corporate purposes.
Dividend Restrictions
The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
Pollution Control Bonds
Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds totaling $157.6 million.
Assets Subject to Lien
In January 2007, the Company’s first mortgage bond indenture was discharged. As a result, there are no longer any first mortgage liens on the Company’s property and the Company no longer has to comply with the covenants and restrictions of the first mortgage
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bond indenture. The Company has granted a lien on its property at Plant Daniel in connection with the issuance of two series of pollution control bonds with an outstanding principal amount of $41 million.
There are no agreements or other arrangements among the affiliated 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 subsidiaries.
Bank Credit Arrangements
At the beginning of 2008, the Company had $125 million of lines of credit with banks subject to renewal each year, all of which remained unused. Of the $125 million, $121 million provides liquidity support for the Company’s commercial paper program and $4 million of variable rate pollution control bonds. In connection with these credit lines, the Company has agreed to pay commitment fees.
Certain credit arrangements contain covenants that limit the level of indebtedness to capitalization to 65%, as defined in the arrangements. At December 31, 2007, the Company was in compliance with these covenants.
In addition, certain credit arrangements contain cross default provisions to other indebtedness that would trigger an event of default if the Company defaulted on indebtedness over a specified threshold. The cross default provisions are restricted only to indebtedness of the Company. The Company is currently in compliance with all such covenants.
The Company borrows primarily through a commercial paper program that has the liquidity support of committed bank credit arrangements. The Company may also borrow through various other arrangements with banks and through an extendible commercial note program. At December 31, 2007, the Company had $40.8 million of commercial paper and no extendible commercial notes outstanding. At December 31, 2006, the Company had $80.4 million of commercial paper and $40 million of bank notes outstanding. During 2007, the peak amount outstanding for short term debt was $147.4 million and the average amount outstanding was $47.5 million. The average annual interest rate on commercial paper was 5.33%.
Financial Instruments
The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company has implemented fuel-hedging programs with the approval of the Florida PSC. The Company enters into hedges of forward electricity sales. There was no material ineffectiveness recorded in earnings in 2007, 2006, and 2005.
At December 31, 2007, the fair value gains/(losses) of energy-related derivative contracts were reflected in the financial statements as follows:
The fair value gains or losses for cash flow hedges that are recoverable through the regulatory fuel clauses are recorded as regulatory assets and liabilities and are recognized in earnings at the same time the hedged items affect earnings. The Company has energy-related hedges in place up to and including 2010.
The Company also enters into derivatives to hedge exposure to interest rate changes. Derivatives related to forecasted transactions are accounted for as cash flow hedges. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. As such, no material ineffectiveness has been recorded in earnings for any period presented. The hedges will be terminated at the time the underlying debt is issued.
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At December 31, 2007 the Company had the following interest rate derivatives accounted for as cash flow hedges:
In 2007, the Company terminated interest rate derivatives, at the same time the related debt was issued, with a notional value of $85 million at a gain of $3.0 million. The hedge cost will be amortized over a 10-year period. For the years 2007, 2006, and 2005, approximately $0.7 million, $0.4 million, and $0.3 million, respectively, of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2008, pre-tax losses of approximately $0.7 million are expected to be reclassified from other comprehensive income to interest expense. The Company has net losses that are being amortized through 2017.
7. COMMITMENTS
Construction Program
The Company is engaged in a continuous construction program, the cost of which is currently estimated to total $410 million in 2008, $426 million in 2009, and $245 million in 2010. The construction program is subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include changes in business conditions; acquisition of additional generating assets; revised load growth estimates; changes in environmental regulations; changes in FERC rules and regulations; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2007, significant purchase commitments were outstanding in connection with the ongoing construction program.
Included in the amounts above are $317 million in 2008, $301 million in 2009, and $134 million in 2010 for environmental expenditures. The Company does not have any new generating capacity under construction. Construction of new transmission and distribution facilities and other capital improvements, including those needed to meet environmental standards for the Company’s existing generation, transmission, and distribution facilities, are ongoing.
Long-Term Service Agreements
The Company has a Long-Term Service Agreement (LTSA) with General Electric (GE) for the purpose of securing maintenance support for combined cycle generating facility. The LTSA provides that GE will perform all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in the LTSA.
In general, the LTSA is in effect through two major inspection cycles of the unit. Scheduled payments to GE, which are subject to price escalation, are made at various intervals based on actual operating hours of the unit. Total remaining payments to GE under the LTSA for facilities owned are currently estimated at $69.0 million over the remaining life of the LTSA, which is currently estimated to be up to 9 years. However, the LTSA contains various cancellation provisions at the option of the Company.
Payments made under the LTSA prior to the performance of any planned inspections are recorded as prepayments. These amounts are included in Current Assets and Deferred Charges and Other Assets in the balance sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed.
Limestone Commitments
As part of the Company’s program to reduce sulfur dioxide emissions from certain of its coal plants, the Company is constructing certain equipment and has entered into various long-term commitments for the procurement of limestone to be used in such equipment. Contracts are structured with tonnage minimums and maximums in order to account for changes in coal burn and sulfur content. The Company has a minimum contractual obligation of 0.8 million tons equating to approximately $63.8 million through 2019. Estimated expenditures over the next five years are none in 2008 and 2009, $5.7 million in 2010, $5.8 million in 2011, and $6.0 million in 2012. Limestone costs are expected to be recovered through the environmental cost recovery clause.
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Fuel and Purchased Power Commitments
To supply a portion of the fuel requirements of the generating plants, the Company has entered into various long-term commitments for the procurement of fossil fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide emission allowances. Natural gas purchase commitments contain fixed volumes with prices based on various indices at the time of delivery. Amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2007. Also, the Company has entered into various long-term commitments for the purchase of capacity and electricity.
Total estimated minimum long-term obligations at December 31, 2007 were as follows:
*
Included above is $76 million in obligations with affiliated companies.
Additional commitments for fuel will be required to supply the Company’s future needs.
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. The creditworthiness of Southern Power is currently inferior to the creditworthiness of the traditional operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.
Operating Leases
The Company has operating lease agreements with various terms and expiration dates. Total operating lease expenses were $4.7 million, $4.9 million, and $3.0 million, for 2007, 2006, and 2005, respectively. Included in these lease expenses are railcar lease costs which are charged to fuel inventory and are allocated to fuel expense as the fuel is used. These expenses are then recovered through the Company’s fuel cost recovery clause. The Company’s share of the lease costs charged to fuel inventories was $4.4 million in 2007, $4.6 million in 2006, and $3.0 million in 2005. The Company includes any step rents, escalations, and lease concessions in its computation of minimum lease payments, which are recognized on a straight-line basis over the minimum lease term.
At December 31, 2007, estimated minimum rental commitments for noncancelable operating leases were as follows:
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The Company and Mississippi Power jointly entered into operating lease agreements for aluminum railcars for the transportation of coal to Plant Daniel. The Company has the option to purchase the railcars at the greater of lease termination value or fair market value or to renew the leases at the end of each lease term. The Company and Mississippi Power also have separate lease agreements for other railcars that do not include purchase options.
In addition to railcar leases, the Company has other operating leases for fuel handling equipment at Plant Daniel. The Company’s share of these leases was charged to fuel handling expense in the amount of $0.3 million in 2007. The Company’s annual lease payments for 2008 to 2010 will average approximately $0.2 million.
8. STOCK OPTION PLAN
Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. As of December 31, 2007, there were 289 current and former employees of the Company participating in the stock option plan. The maximum number of shares of Southern Company common stock that may be issued under this plan may not exceed 40 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. For certain stock option awards a change in control will provide accelerated vesting.
The Company’s activity in the stock option plan for 2007 is summarized below:
The number of stock options vested, and expected to vest in the future, as of December 31, 2007 was not significantly different from the number of stock options outstanding at December 31, 2007 as stated above. As of December 31, 2007, the weighted average remaining contractual term for the options outstanding and options exercisable was 6.4 years and 5.2 years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $9.5 million and $7.9 million, respectively.
As of December 31, 2007, there was $0.5 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted average period of approximately 10 months.
The total intrinsic value of options exercised during the years ended December 31, 2007, 2006, and 2005 was $3.0 million, $1.6 million, and $4.4 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises for the years ended December 31, 2007, 2006, and 2005 totaled $1.1 million, $0.6 million, and $1.7 million, respectively.
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9. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 2007 and 2006 are as follows:
The Company’s business is influenced by seasonal weather conditions.
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MISSISSIPPI POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Mississippi Power Company 2007 Annual Report
The management of Mississippi Power Company (the “Company”) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Under management’s supervision, an evaluation of the design and effectiveness of the Company’s internal control over financial reporting was conducted based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2007.
This Annual Report does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report.
/s/ Anthony J. Topazi
Anthony J. Topazi
President and Chief Executive Officer
/s/ Frances V. Turnage
Frances V. Turnage
Vice President, Treasurer, and Chief Financial Officer
February 25, 2008
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Mississippi Power Company
We have audited the accompanying balance sheets and statements of capitalization of Mississippi Power Company (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2007 and 2006, 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, 2007. 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 II-310 to II-342) present fairly, in all material respects, the financial position of Mississippi Power Company at December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the financial statements, in 2006 the Company changed its method of accounting for the funded status of defined benefit pension and other postretirement plans.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 25, 2008
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Mississippi Power Company 2007 Annual Report
OVERVIEW
Business Activities
Mississippi Power Company (Company) operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Mississippi and 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 stable regulatory environment, to achieve energy sales growth, and to effectively manage and secure timely recovery of rising costs. The Company has various regulatory mechanisms that operate to address cost recovery. Since 2005, the Company has completed a number of regulatory proceedings that provide for the timely recovery of costs.
Appropriately balancing required costs and capital expenditures with reasonable retail rates will continue to challenge the Company for the foreseeable future. Hurricane Katrina, the worst natural disaster in the Company’s history, hit the Gulf Coast of Mississippi in August 2005, causing substantial damage to the Company’s service territory. All of the Company’s 195,000 customers were without service immediately after the storm. Through a coordinated effort with Southern Company, as well as non-affiliated companies, the Company restored power to all who could receive it within 12 days. However, due to obstacles in the rebuilding process, the Company has over 9,000 fewer retail customers as of December 31, 2007 as compared to pre-storm levels. In 2006, the Company received from the Mississippi Development Authority (MDA) a Community Development Block Grant (CDBG) in the amount of $276.4 million for costs related to Hurricane Katrina, of which $267.6 million was for the retail portion of the Hurricane Katrina restoration costs. In 2007, the Company received $109.3 million of storm restoration bond proceeds under the state bond program of which $25.2 million was for retail storm restoration cost, $60.0 million was to increase the Company’s retail property damage reserve, and $24.1 million was to cover the retail portion of construction of a new storm operations center.
The Company’s retail base rates are set under the Performance Evaluation Plan (PEP), a rate plan approved by the Mississippi Public Service Commission (PSC). PEP was designed with the objective to reduce the impact of rate changes on the customer and provide incentives for the Company to keep customer prices low and customer satisfaction and reliability high.
In December 2007, the Company made its annual PEP filing for the projected 2008 test period, resulting in a rate increase of 1.983% or $15.5 million annually, effective January 2008. See Note 3 to the financial statements under “Retail Regulatory Matters - Performance Evaluation Plan” for more information on PEP.
Key Performance Indicators
In striving to maximize shareholder value while providing cost effective energy to customers, the Company continues to focus on several key indicators. These indicators are used to measure the Company’s performance for customers and employees.
Recognizing the critical role in the Company’s success played by the Company’s employees, employee-related measures are a significant management focus. These measures include safety and inclusion. The 2007 safety performance of the Company was the second best in the history of the Company with an Occupational Safety and Health Administration Incidence Rate of 0.62. This achievement resulted in the Company being recognized as one of the top in safety performance among all utilities in the Southeastern Electric Exchange. Inclusion initiatives resulted in performance above target for the year. In recognition that the Company’s long-term financial success is dependent upon how well it satisfies its customers’ needs, the Company’s retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to the Company’s allowed return. PEP measures the Company’s performance on a 10-point scale as a weighted average of results in three areas: average customer price, as compared to prices of other regional utilities (weighted at 40%); service reliability, measured in outage minutes per customer (40%); and customer satisfaction, measured in a survey of residential customers (20%). See Note 3 to the financial statements under “Retail Regulatory Matters - Performance Evaluation Plan” for more information on PEP.
In addition to the PEP performance indicators, the Company focuses on other performance measures, including broader measures of customer satisfaction, plant availability, system reliability, and net income. The Company’s financial success is directly tied to the satisfaction of its customers. Management uses customer satisfaction surveys to evaluate the Company’s results. Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of 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. Net income after dividends on preferred stock is the primary component of the Company’s contribution to Southern
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Mississippi Power Company 2007 Annual Report
Company’s earnings per share goal. The Company’s 2007 results compared with its targets for some of these key indicators are reflected in the following chart.
See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The financial performance achieved in 2007 reflects the continued emphasis that management places on all of these indicators, as well as the commitment shown by employees in achieving or exceeding management’s expectations.
Earnings
The Company’s net income after dividends on preferred stock was $84.0 million in 2007 compared to $82.0 million in 2006. The 2.4% increase in 2007 was primarily the result of a $21.3 million increase in territorial base revenues which was a result of a retail base rate increase effective April 1, 2006 and territorial sales growth, a $10.9 million increase in total other income and expense as a result of charitable contributions in 2006 and a gain on a contract termination approved by the Federal Energy Regulatory Commission (FERC) in 2007. These increases were partially offset by a $18.2 million increase in non-fuel related expenses and an $8.7 million increase in depreciation and amortization expenses primarily due to the amortization of a regulatory liability related to Plant Daniel capacity. See FUTURE EARNINGS POTENTIAL - “FERC and Mississippi PSC Matters - Retail Regulatory Matters” herein for additional information.
Net income after dividends on preferred stock of $82.0 million in 2006 increased when compared to $73.8 million in 2005 primarily as a result of a $25.9 million increase in retail base rates which became effective April 1, 2006, a $4.7 million increase in wholesale base revenues, and a $2.9 million decrease in non-fuel related expenses, partially offset by a $13.3 million increase in depreciation and amortization expenses due to the amortization of a regulatory liability related to Plant Daniel capacity and a depreciation rate increase effective January 1, 2006, an $8.6 million decrease in total other income and expense as a result of charitable contributions, and higher interest rates on long-term debt.
Net income after dividends on preferred stock of $73.8 million in 2005 decreased when compared to $76.8 million in 2004 primarily due to a $15.7 million decrease in retail base revenue due to the loss of customers as a result of Hurricane Katrina and a $2.5 million increase in non-fuel related expenses primarily resulting from increased employee benefit expenses, partially offset by a $5.8 million decrease in depreciation and amortization expenses due to the amortization of a regulatory liability related to Plant Daniel capacity, a $3.3 million increase in wholesale base revenues, a $1.2 million increase in other revenues, and a $2.0 million decrease in dividends on preferred stock as compared to 2004 resulting from the loss on redemption of preferred stock recognized in the third quarter 2004.
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RESULTS OF OPERATIONS
A condensed statement of income follows:
Operating Revenues
Details of the Company’s operating revenues in 2007 and the prior two years were as follows:
Total retail revenues for 2007 increased 12.4% when compared to 2006 primarily as a result of an increase in territorial sales growth, a retail base rate increase effective April 1, 2006 and the Environmental Compliance Overview (ECO) Plan rate effective May 2007. Higher fuel costs also contributed to the increase. Total retail revenues for 2006 increased 4.6% when compared to 2005 primarily as a result of a retail base rate increase effective April 1, 2006. Higher fuel costs also contributed to the increase. Total retail revenues
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for 2005 increased 5.9% when compared to 2004 as a result of higher fuel revenue due to the increase in fuel cost. This increase in retail revenues was partially offset by reductions for the loss of customers in all major classes as a result of Hurricane Katrina.
Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power, and do not affect net income. The fuel cost recovery and other revenues increased in 2007 when compared to 2006 as a result of higher fuel costs. In 2006, fuel cost recovery and other revenues increased as compared to 2005 as a result of higher fuel costs and an increase in kilowatt-hours (KWH) generated. During 2005, fuel cost recovery and other revenues increased as compared to 2004 due to higher fuel costs.
Wholesale revenues to non-affiliates are influenced by the non-affiliate utilities’ own customer demand, plant availability, and fuel costs. Wholesale revenues to non-affiliates increased $54.3 million, or 20.2%, in 2007 as compared to 2006 as a result of a $51.5 million increase in energy revenues, of which $32.0 million was associated with increased sales and $19.5 million was associated with higher fuel prices, and a $2.8 million increase in capacity revenues. In 2006, wholesale revenues to non-affiliates decreased $14.6 million, or 5.1%, compared to 2005. This decrease resulted from a $14.7 million decrease in energy revenues, of which $10.1 million was associated with decreased sales and $4.6 million was associated with lower fuel prices. Wholesale revenues to non-affiliates increased in 2005 by $17.5 million, or 6.6%, compared to 2004. This increase primarily resulted from an increase in price per KWH resulting from higher fuel costs.
Included in wholesale revenues to non-affiliates are revenues from rural electric cooperative associations and municipalities located in southeastern Mississippi. Compared to the prior year, KWH sales to these utilities increased 4.3% in 2007 due to growth in the service territory, increased 8.9% in 2006 compared to 2005 due to growth in the service territory and recovery from Hurricane Katrina in 2006, and decreased 5.0% in 2005 compared to 2004 due to Hurricane Katrina. The related revenues increased 12.6%, 7.1%, and 16.2%, in 2007, 2006, and 2005, respectively. The customer demand experienced by these utilities is determined by factors very similar to those experienced by the Company. On February 15, 2008, the Company received notice of termination of an approximately 100 MW territorial wholesale market based contract effective March 31, 2011. This termination is estimated to reduce the Company’s annual territorial wholesale base revenues by approximately $12 million.
Short-term opportunity energy sales are also included in sales for resale to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above the Company’s variable cost to produce the energy. KWH sales to non-territorial customers increased 41.0% compared to 2006 primarily due to more off-system sales resulting from increased system generation.
Wholesale revenues from sales to affiliated companies within the Southern Company system will vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliated sales and purchases are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the FERC. Wholesale revenues from sales to affiliated companies decreased 39.5% in 2007, when compared to 2006, increased 51.6% in 2006, when compared to 2005, and increased 13.8% in 2005, when compared to 2004. These energy sales do not have a significant impact on earnings since the energy is generally sold at marginal cost.
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Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2007 and percent change by year were as follows:
Total retail KWH sales increased in 2007 when compared to 2006 due to continuing restoration of customers lost after Hurricane Katrina. Total retail KWH sales increased in 2006 when compared to 2005 due to restoration of customers lost after Hurricane Katrina in 2005. Total retail KWH sales decreased in 2005 when compared to 2004 as the result of the loss of customers following Hurricane Katrina.
Fuel and Purchased Power Expenses
Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market. Details of the Company’s electricity generated and purchased were as follows:
Fuel and purchased power expenses were $590.1 million in 2007, an increase of $78.3 million, or 15.3%, above the prior year costs. This increase was primarily due to a $63.8 million increase in the cost of fuel and purchased power and a $14.5 million increase related to total KWHs generated and purchased. In 2006, fuel and purchased power expenses were $511.9 million, an increase of $9.8 million, or 2.0%, above the prior year costs. This increase was primarily due to an increase of $9.7 million in the cost of fuel and purchased power. Fuel and purchased power expenses in 2005 were $502.1 million, an increase of $70.4 million, or 16.3%, above the prior year costs. This increase was the result of a $127.6 million increase in the cost of fuel and purchased power and a $57.2 million decrease related to total KWHs generated and purchased.
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Mississippi Power Company 2007 Annual Report
Fuel expense increased $55.6 million in 2007 as compared to 2006. Approximately $56.8 million in additional fuel expenses resulted from higher coal, gas, transportation prices, and emission allowances, which were partially offset by a $1.2 million decrease in generation from Mississippi Power-owned facilities. Fuel expense increased $80.1 million in 2006 as compared to 2005 as a result of increases in fuel costs and an increase in generation. This increase in fuel expense is due to a $30.0 million increase in the cost of fuel due to higher coal, gas, transportation, and emission allowance prices and a $50.0 million increase related to more KWHs generated. Fuel expense increased $33.7 million in 2005 as compared to 2004. Approximately $71 million in additional fuel expenses resulted from higher coal, gas, transportation prices, and emission allowances, which were partially offset by a $36 million decrease resulting from unit outages that reduced generation.
Purchased power expense increased $22.6 million, or 30.9%, in 2007 when compared to 2006. The increase was primarily due to an increase in the cost of purchased power and an increase in the amount of energy purchased which was partially due to a decrease in generation resulting from plant outages. Purchased power expense decreased $70.2 million, or 49%, in 2006 when compared to 2005. The decrease was primarily due to more generation being available to meet customer demand and a decrease in the cost of purchased power. In 2005, purchased power expense increased $36.7 million, or 34.4%, when compared to 2004. The increase is primarily the result of the reduction in generation due to the damage caused by Hurricane Katrina. Energy purchases vary from year to year depending on demand and the availability and cost of the Company’s generating resources. These expenses do not have a significant impact on earnings since the energy purchases are generally offset by energy revenues through the Company’s fuel cost recovery clause.
While there has been a significant upward trend in the cost of coal and natural gas since 2003, prices moderated somewhat in 2006 and 2007. Coal prices have been influenced by a worldwide increase in demand from developing countries, as well as increases in mining and fuel transportation costs. While demand for natural gas in the United States continued to increase in 2007, natural gas supplies have also risen due to increased production and higher storage levels.
Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL - “PSC Matters - Fuel Cost Recovery” and Note 1 to the financial statements under “Fuel Costs” for additional information.
Other Operations and Maintenance Expenses
Total other operations and maintenance expenses increased $18.6 million from 2006 to 2007. Other operations expense increased $15.1 million, or 8.8%, in 2007 compared to 2006 primarily as a result of a $4.1 million increase in generation construction screening, a $3.3 million insurance recovery for storm restoration expense recognized in 2006, a $2.1 million increase in employee benefits primarily due to increase in medical expense, a $2.0 million increase in outside and other contract services, and a $2.0 million increase in scheduled production projects. Maintenance expense increased $3.5 million, or 5.2%, in 2007 when compared to 2006, primarily as a result of a $5.5 million increase in generation maintenance expense primarily due to outage work in 2007, partially offset by a $2.0 million decrease in transmission and distribution maintenance expenses due primarily to the deferral of these expenses pursuant to the regulatory accounting order from the Mississippi PSC.
In 2006, total other operations and maintenance expenses decreased $3.0 million compared to 2005. Other operations expense increased $1.9 million, or 1.1%, in 2006 compared to 2005 primarily as a result of a $1.8 million increase in distribution operations expense and a $1.5 million increase in employee benefit expenses, partially offset by a $1.0 million decrease in bad debt expense. Maintenance expense decreased $4.9 million, or 6.8%, in 2006, primarily due to the $3.4 million accrual of certain expenses arising from Hurricane Katrina related to the wholesale portion of the business in 2005 and the $2.8 million partial recovery of these expenses from the CDBG in 2006, partially offset by a $0.5 million increase in 2006 due to the increased operation of combined cycle units as gas costs decreased in 2006 when compared to 2005.
In 2005, total other operations and maintenance expenses increased $2.1 million compared to 2004. In 2005, other operations expense increased $7.9 million, or 4.9%, compared to 2004 primarily as a result of a $5.2 million increase in employee benefit expenses, a $1.7 million increase in rent expense on the Plant Daniel combined cycle lease, and higher bad debt expense of $1.0 million primarily resulting from Hurricane Katrina. In 2005, maintenance expense decreased $5.7 million, or 7.5%, over the prior year, primarily as a result of a $1.1 million decrease in the operation of combined cycle units due to higher gas prices in 2005 when compared to 2004 and a $4.5 million decrease in maintenance expense associated with changes in scheduled maintenance as a result of restoration efforts.
See FINANCIAL CONDITION AND LIQUIDITY - “Off-Balance Sheet Financing Arrangements” and Notes 3 and 7 to the financial statements under “Retail Regulatory Matters - Performance Evaluation Plan” and “Operating Leases - Plant Daniel Combined Cycle
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Mississippi Power Company 2007 Annual Report
Generating Units,” respectively, for additional information. See FUTURE EARNINGS POTENTIAL - “PSC Matters - Storm Damage Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters - Storm Damage Cost Recovery” for additional information. See Note 7 to the financial statements under “Long-Term Service Agreements” for further information.
Depreciation and Amortization
Depreciation and amortization expenses increased $13.5 million in 2007 compared to 2006 due to a regulatory liability recorded in 2003 in connection with the Mississippi PSC’s accounting order on Plant Daniel capacity and an increase in amortization of environmental costs related to the approved ECO Plan. Depreciation and amortization expenses increased $13.3 million in 2006 compared to 2005 due to amortization related to a regulatory liability recorded in 2003 in connection with the Mississippi PSC’s accounting order on Plant Daniel capacity and the impact of a new depreciation study effective January 1, 2006. Depreciation and amortization expenses decreased $5.8 million in 2005 as compared to the prior year primarily as a result of amortization related to a regulatory liability recorded in 2003 in connection with the Mississippi PSC’s accounting order on the Plant Daniel capacity. See Note 3 under “Retail Regulatory Matters - Performance Evaluation Plan” and “Environmental Compliance Overview Plan” for additional information.
Taxes Other than Income Taxes
Taxes other than income taxes decreased 0.9% in 2007 compared to 2006 primarily as a result of a $2.0 million decrease in ad valorem taxes, partially offset by a $1.5 million increase in municipal franchise taxes. In 2006, taxes other than income taxes increased 1.4% over the prior year primarily as a result of a $0.5 million increase in ad valorem taxes and a $0.3 million increase in municipal franchise taxes. Taxes other than income taxes increased 8.1% in 2005 as compared to 2004 primarily due to a $2.9 million increase in ad valorem taxes and a $1.1 million increase in municipal franchise taxes. The retail portion of the increase in ad valorem taxes is recoverable under the Company’s ad valorem tax cost recovery clause and, therefore, does not affect net income. The increase in municipal franchise taxes is directly related to the increase in total retail revenues.
Total Other Income and (Expense)
The $10.9 million increase in total other income and expense in 2007 compared to 2006 is primarily due to higher charitable contributions in 2006 as compared to 2007 and a gain on a contract termination approved by the FERC in 2007. The $8.6 million decrease in total other income and expense in 2006 compared to 2005 is primarily due to charitable contributions and higher interest rates on long-term debt. In 2005, the increases in total other income and expense compared to 2004 are due to a reversal, as a result of changes in the legal and regulatory environment, of a $2.5 million liability originally recorded for the potential assessment of interest associated with a customer advance. This amount was partially offset by expenses related to recovery from Hurricane Katrina.
Effects of Inflation
The Company is subject to rate regulation that is based on the recovery of costs. PEP is based on annual projected costs, including estimates for inflation. When historical costs are included, or when inflation exceeds projected costs used in rate regulation or market- based prices, the effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. In addition, the income tax laws are based on historical costs. The inflation rate has been relatively low in recent years and any adverse effect of inflation on the Company has not been significant.
FUTURE EARNINGS POTENTIAL
General
The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in southeast Mississippi and wholesale customers in the southeastern United States. Prices for electricity provided by the Company to retail customers are set by the Mississippi PSC under cost-based regulatory principles. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. Prices for wholesale electricity sales, interconnecting transmission lines and the exchange of electric power are regulated by the FERC. See ACCOUNTING POLICIES - “Application of Critical Accounting Policies and Estimates - Electric Utility Regulation” herein and Note 3 to the financial statements under “FERC Matters” and “Retail Regulatory Matters” for additional information about regulatory matters.
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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 business of selling electricity. These factors include the ability of the Company to maintain a stable regulatory environment that continues to allow for the recovery of all prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the Company’s service area in the aftermath of Hurricane Katrina.
Environmental Matters
Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. Some of the factors driving the potential for such an increase are higher commodity costs, market demand for labor, and scope additions and clarifications. The timing, specific requirements, and estimated costs could also change as environmental statutes and regulations are adopted or modified. See Note 3 to the financial statements under “Environmental Matters” for additional information.
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama after Alabama Power was dismissed from the original action. In these lawsuits, the EPA alleged that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including one co-owned by the Company. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The action against Georgia Power has been administratively closed since the spring of 2001, and the case has not been reopened.
In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving the alleged NSR violations at Plant Miller. The consent decree required Alabama Power to pay $100,000 to resolve the government’s claim for a civil penalty and to donate $4.9 million of sulfur dioxide emission allowances to a nonprofit charitable organization and formalized specific emissions reductions to be accomplished by Alabama Power, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in Alabama granted Alabama Power’s motion for summary judgment and entered final judgment in favor of Alabama Power on the EPA’s claims related to all of the remaining plants: Plants Barry, Gaston, Gorgas, and Greene County.
The plaintiffs appealed the district court’s decision to the U.S. Court of Appeals for the Eleventh Circuit, and the appeal was stayed by the Appeals Court pending the U.S. Supreme Court’s decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke Energy case in April 2007. On October 5, 2007, the U.S. District Court for the Northern District of Alabama issued an order in the Alabama Power case indicating a willingness to re-evaluate its previous decision in light of the Supreme Court’s Duke Energy opinion. On December 21, 2007, the Eleventh Circuit vacated the district court’s decision in the Alabama Power case and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court’s decision in the Duke Energy case.
The Company believes it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in either of these cases could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
The EPA has issued a series of proposed and final revisions to its NSR regulations under the Clean Air Act, many of which have been subject to legal challenges by environmental groups and states. In June 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s revisions to NSR regulations that were issued in December 2002 but vacated portions of those revisions addressing the exclusion of certain pollution control projects. These regulatory revisions have been adopted by the State of
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Mississippi. In March 2006, the U.S. Court of Appeals for the District of Columbia Circuit also vacated an EPA rule which sought to clarify the scope of the existing routine maintenance, repair, and replacement exclusion. The EPA has also published proposed rules clarifying the test for determining when an emissions increase subject to the NSR permitting requirements has occurred. The impact of these proposed rules will depend on adoption of the final rules by the EPA and the State of Mississippi’s implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.
Carbon Dioxide Litigation
In July 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005, and no decision has been issued. The ultimate outcome of these matters cannot be determined at this time.
Environmental Statutes and Regulations
General
The Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; and the Endangered Species Act.
Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through the Company’s ECO Plan. See Note 3 to the financial statements under “Retail Regulatory Matters - Environmental Compliance Overview Plan” for additional information. Through 2007, the Company had invested approximately $161.0 million in capital projects to comply with these requirements, with annual totals of $17.0 million, $4.8 million, and $4.0 million for 2007, 2006, and 2005, respectively. The Company expects that capital expenditures to assure compliance with existing and new statutes and regulations will be an additional $74.4 million, $128.2 million, and $91.9 million for 2008, 2009, and 2010, respectively. The Company’s compliance strategy is impacted by changes to existing environmental laws, statutes, and regulations, the cost, availability, and existing inventory of emission allowances, and the Company’s fuel mix. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY - “Capital Requirements and Contractual Obligations” herein.
Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company. New environmental legislation or regulations, or changes to existing statutes or regulations, could affect many areas of the Company’s operations; however, the full impact of any such changes cannot be determined at this time.
Air Quality
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2007, the Company had spent approximately $89.0 million in reducing sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been announced and are currently being installed on several units to further reduce SO2, NOx, and mercury emissions, maintain compliance with existing regulations, and meet new requirements.
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Mississippi Power Company 2007 Annual Report
In 2004, the EPA designated nonattainment areas under an eight-hour ozone standard. No area within the Company’s service area was designated as nonattainment under the eight-hour ozone standard. On June 20, 2007, the EPA proposed additional revisions to the current eight-hour ozone standard which, if enacted, could result in designation of new nonattainment areas within the Company’s service territory. The EPA has requested comment and is expected to publish final revisions to the standard in 2008. The impact of this decision, if any, cannot be determined at this time and will depend on subsequent legal action and/or future nonattainment designations and state regulatory plans.
The EPA issued the final Clean Air Interstate Rule in March 2005. This cap-and-trade rule addresses power plant SO2 and NOx emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including the State of Mississippi, are subject to the requirements of the rule. The rule calls for additional reductions of NOx and/or SO2 to be achieved in two phases, 2009/2010 and 2015. The State of Mississippi has an EPA-approved plan for implementing this rule. These reductions will be accomplished by the installation of additional emission controls at the Company’s coal-fired facilities and/or by the purchase of emission allowances from a cap-and-trade program.
The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized in July 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves (1) the application of Best Available Retrofit Technology (BART) to certain sources built between 1962 and 1977 and (2) the application of any additional emissions reductions which may be deemed necessary for each designated area to achieve reasonable progress by 2018 toward the natural conditions goal. Thereafter, for each 10-year planning period, additional emissions reductions will be required to continue to demonstrate reasonable progress in each area during that period. For power plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for SO2 and NOx. Extensive studies were performed for each of the Company’s affected units to demonstrate that additional particulate matter controls are not necessary under BART. States are currently completing implementation strategies for BART and any other measures required to achieve the first phase of reasonable progress.
The impacts of the new eight-hour ozone standard and the Clean Air Visibility Rule on the Company will depend on the development and implementation of rules at the federal and/or state level. Therefore, the full effects of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO2 and NOx, emission controls within the next several years to assure continued compliance with applicable air quality requirements.
In March 2005, the EPA published the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emission allowance trading market. The final Clean Air Mercury Rule was challenged in the U.S. Court of Appeals for the District of Columbia Circuit. The petitioners alleged that the EPA was not authorized to establish a cap-and-trade program for mercury emissions and instead the EPA must establish maximum achievable control technology standards for coal-fired electric utility steam generating units. On February 8, 2008, the court issued its ruling and vacated the Clean Air Mercury Rule. Any significant changes in the Company’s overall environmental compliance strategy will depend on the outcome of any appeals and/or future federal and state rulemakings. Future rulemakings could require emission reductions more stringent than required by the Clean Air Mercury Rule.
Water Quality
In July 2004, the EPA published its final technology-based regulations under the Clean Water Act for the purpose of reducing impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures. The rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants. On January 25, 2007, the U.S. Court of Appeals for the Second Circuit overturned and remanded several provisions of the rule to the EPA for revisions. Among other things, the court rejected the EPA’s use of “cost-benefit” analysis and suggested some ways to incorporate cost considerations. The full impact of these regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by the State of Mississippi regulatory agencies and, therefore, cannot be determined at this time.
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Environmental Remediation
The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and release of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in the 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. The Company has received authority from the Mississippi PSC to recover approved environmental compliance costs through specific retail rate clauses. Within limits approved by the Mississippi PSC, these rates are adjusted annually. See Note 3 to the financial statements under “Environmental Matters - Environmental Remediation” and “Retail Regulatory Matters - Environmental Compliance Overview Plan” for additional information.
Global Climate Issues
Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions continue to be considered in Congress. The ultimate outcome of these proposals cannot be determined at this time; however, mandatory restrictions on the Company’s greenhouse gas emissions could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. The EPA is currently developing its response to this decision. Regulatory decisions that will follow from this response may have implications for both new and existing stationary sources, such as power plants. The ultimate outcome of these rulemaking activities cannot be determined at this time; however, as with the current legislative proposals, mandatory restrictions on the Company’s greenhouse gas emissions could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
In addition, some states are considering or have undertaken actions to regulate and reduce greenhouse gas emissions. For example, on July 13, 2007, the Governor of the State of Florida signed three executive orders addressing reduction of greenhouse gas emissions within the state, including statewide emission reduction targets beginning in 2017. Included in the orders is a directive to the Florida Secretary of Environmental Protection to develop rules adopting maximum allowable emissions levels of greenhouse gases for electric utilities, consistent with the statewide emission reduction targets, and a request to the Florida PSC to initiate rulemaking requiring utilities to produce at least 20% of their electricity from renewable sources. The impact of any similar state regulation on the Company will depend on the future development, adoption, and implementation of state laws or rules governing greenhouse gas emissions, and the ultimate outcome cannot be determined at this time.
International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. Current efforts focus on a potential successor to the Kyoto Protocol for the post-2008 through 2012 timeframe. The outcome and impact of the international negotiations cannot be determined at this time.
The Company continues to evaluate its future energy and emission profiles and is participating in voluntary programs to reduce greenhouse gas emissions and to help develop and advance technology to reduce emissions.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.
In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales by the Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level.
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In late June and July 2007, hearings were held in this proceeding and the presiding administrative law judge issued an initial decision on November 9, 2007, regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the Company to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates, and could also result in refunds of up to $8.4 million, plus interest. The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter.
On June 21, 2007, the FERC issued its final rule regarding market-based rate authority. The FERC generally retained its current market-based rate standards. The impact of this order and its effect on the generation dominance proceeding cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies (including the Company), Southern Power, and Southern Company Services, Inc. (SCS), as agent, under the terms of which the power pool of Southern Company is operated, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct.
In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms and Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. Southern Company filed with the FERC in November 2006 a compliance plan in connection with the order. On April 19, 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan is not expected to have a material impact on the Company’s financial statements. On November 19, 2007, Southern Company notified the FERC that the plan had been implemented and the FERC division of audits subsequently began an audit pertaining to compliance implementation and related matters, which is ongoing.
PSC Matters
Performance Evaluation Plan
See Note 3 to the financial statements under “Retail Regulatory Matters - Performance Evaluation Plan” for information on the Company’s retail base rates. In May 2004, the Mississippi PSC approved the Company’s request to reclassify 266 megawatts of Plant Daniel Units 3 and 4 capacity to jurisdictional cost of service effective January 1, 2004, and authorized the Company to include the related costs and revenue credits in jurisdictional rate base, cost of service, and revenue requirement calculations for purposes of retail rate recovery. In the May 2004 order establishing the Company’s forward-looking Rate Schedule PEP, the Mississippi PSC ordered that the Mississippi Public Utility Staff and the Company review the operations of the PEP in 2007. By mutual agreement, this review was deferred and will occur in 2008. The outcome of this review cannot now be determined.
In April 2007, the Mississippi PSC issued an order allowing the Company to defer approximately $10.4 million of certain reliability related maintenance costs beginning January 1, 2007, and recover them evenly over a four-year period beginning January 1, 2008. These costs related to maintenance that was needed as follow-up to emergency repairs that were made subsequent to Hurricane Katrina. At December 31, 2007, the Company had incurred and deferred the retail portion of $9.5 million of such costs, of which $2.4 million is included in current assets as other regulatory assets and $7.1 million is included in long-term other regulatory assets.
In September 2007, the Mississippi PSC staff and the Company entered into a stipulation that included adjustments to expenses which resulted in a one-time credit to retail customers of approximately $1.1 million. In November 2007, the Mississippi PSC issued an order requiring the Company to refund this amount to its retail customers no later than December 2007. This amount was totally refunded as a credit to customer bills by December 31, 2007.
In December 2007, the Company submitted its annual PEP filing for 2008, which resulted in a rate increase of 1.983% or $15.5 million annually, effective January 2008. In December 2006, the Company submitted its annual PEP filing for 2007, which resulted in no rate change.
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In December 2007, the Company received an order from the Mississippi PSC requiring it to defer $1.4 million associated with the retail portion of certain tax credits and favorable adjustments related to permanent differences pertaining to its 2006 income tax returns filed in September 2007. These tax differences have been recorded in a regulatory liability included in the current portion of other regulatory liabilities and will be amortized ratably over a twelve month period beginning January 2008.
System Restoration Rider
In September 2006, the Company filed with the Mississippi PSC a request to implement a System Restoration Rider (SRR) to increase the Company’s cap on the property damage reserve and to authorize the calculation of an annual property damage accrual based on a formula. The purpose of the SRR is to provide for recovery of costs associated with property damage (including certain property insurance and the costs of self insurance) and to facilitate the Mississippi PSC’s review of these costs. The Company is required to make annual SRR filings to determine the revenue requirement associated with any property damage. The Company recorded a regulatory liability in the amount of approximately $2.4 million in 2006 and $0.6 million in 2007 for the estimated amount due to retail customers through SRR. The Company along with the Mississippi Public Utilities Staff has agreed and stipulated to a revised SRR calculation method that would no longer require the Mississippi PSC to set a cap on the property damage reserve or to authorize the calculation of an annual property damage accrual. Under the revised SRR calculation method, the Mississippi PSC would periodically agree on SRR revenue levels that would be developed based on historical data, expected exposure, type and amount of insurance coverage excluding insurance costs, and other relevant information. It is anticipated that the Mississippi PSC would agree on the applicable SRR revenue level every three years, unless a significant change in circumstances occurs such that the Company and the Mississippi Public Utilities Staff or the Mississippi PSC deems that a more frequent change would be just, reasonable and in the public interest. The Company will submit annual filings setting forth SRR-related revenues, expenses and investment for the projected filing period, as well as the true-up for the prior period. The Company is currently waiting on a final order from the Mississippi PSC determining the final disposition of the regulatory liability and determination of the final SRR rate schedule.
Environmental Compliance Overview Plan
On February 1, 2008, the Company filed with the Mississippi PSC its annual ECO Plan evaluation for 2008, which resulted in an 18 cents per 1,000 KWH decrease in the rate for retail residential customers. Hearings with the Mississippi PSC are expected to be held in April 2008. The outcome of the 2008 filing cannot now be determined. In April 2007, the Mississippi PSC approved the Company’s 2007 ECO Plan, which included an 86 cents per 1,000 KWH increase for retail residential customers. This increase represented an addition of approximately $7.5 million in annual revenues for the Company. The new rates were effective in April 2007. See Note 3 to the financial statements under “Retail Regulatory Matters - Environmental Compliance Overview Plan” for additional information.
Fuel Cost Recovery
The Company establishes, annually, a fuel cost recovery factor that is approved by the Mississippi PSC. Over the past several years, the Company has continued to experience higher than expected fuel costs for coal and natural gas. The Company is required to file for an adjustment to the fuel cost recovery factor annually; such filing occurred in November 2007. As a result, the Mississippi PSC approved an increase in the fuel cost recovery factor effective January 2008 in an amount equal to 4.2% of total retail revenues. The Company’s operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, this increase to the billing factor will have no significant effect on the Company’s revenues or net income, but will increase annual cash flow. At December 31, 2007, the amount of under recovered fuel costs included in the balance sheets was $40.5 million compared to $50.8 million at December 31, 2006.
Storm Damage Cost Recovery
In August 2005, Hurricane Katrina hit the Gulf Coast of the United States and caused significant damage within the Company’s service area. The estimated total storm restoration costs relating to Hurricane Katrina through December 31, 2007 of $302.4 million, which was net of expected insurance proceeds of approximately $77 million, without offset for the property damage reserve of $3.0 million, was affirmed by the Mississippi PSC in June 2006, and the Company was ordered to establish a regulatory asset for the retail portion. The Mississippi PSC issued an order directing the Company to file an application with the MDA for a CDBG. In October 2006, the Company received from the MDA a CDBG in the amount of $276.4 million, which was allocated to both the retail and wholesale jurisdictions. In the same month, the Mississippi PSC issued a financing order that authorized the issuance of system restoration bonds for the remaining $25.2 million of the retail portion of storm recovery costs not covered by the CDBG. The
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Company incurred the $302.4 million total storm costs affirmed by the Mississippi PSC as of December 31, 2007, and will report the retail regulatory liability balance of $0.1 million to the Mississippi PSC to determine the final disposition of this balance.
The Company maintains a reserve to cover the cost of damage from major storms to its transmission and distribution facilities and generally the cost of uninsured damage to its generation facilities and other property. A 1999 Mississippi PSC order allowed the Company to accrue $1.5 million to $4.6 million to the reserve annually, with a maximum reserve totaling $23 million. In October 2006, in conjunction with the Mississippi PSC Hurricane Katrina-related financing order, the Mississippi PSC ordered the Company to cease all accruals to the retail property damage reserve, until a new reserve cap is established. However, in the same financing order, the Mississippi PSC approved the replenishment of the property damage reserve with $60 million to be funded with a portion of the proceeds of bonds to be issued by the Mississippi Development Bank on behalf of the State of Mississippi and reported as liabilities by the State of Mississippi. These funds were received in June 2007.
In June 2006, the Mississippi PSC issued an order certifying actual storm restoration costs relating to Hurricane Katrina through April 30, 2006, of $267.9 million and affirmed estimated additional costs through December 31, 2007, of $34.5 million, for total storm restoration costs of $302.4 million, which was net of expected insurance proceeds of approximately $77 million, without offset for the property damage reserve of $3.0 million. Of the total amount, $292.8 million was estimated to be the Company’s retail jurisdiction. The order directed the Company to file an application with the MDA for a CDBG.
In October 2006, the Company received from the MDA a CDBG in the amount of $276.4 million. The Company has appropriately allocated and applied these CDBG proceeds to both retail and wholesale storm restoration cost recovery. The retail portion of $267.6 million was applied to the retail regulatory asset in the balance sheets. For the remaining wholesale portion of $8.8 million, $3.3 million was credited to operations and maintenance expense in the statements of income and $5.5 million was applied to accumulated provision for depreciation in the balance sheets. In 2006, the CDBG proceeds related to capital of $152.7 million and $120.3 million related to retail operations and maintenance expense were included in the statements of cash flows as separate line items. In 2007, the storm restoration bond proceeds related to $35.0 million capital, of which $10.9 million related to retail restoration and $24.1 million related to the storm operations center, and $14.3 million related to retail operations and maintenance expenses are included in the statements of cash flows as separate line items. The cash portions of storm costs are included in the statements of cash flows under Hurricane Katrina accounts payable, property additions, and cost of removal, net of salvage and totaled approximately $0.1 million, $12.5 million, and $(8.1) million, respectively, for 2007, $50.5 million, $54.2 million, and $4.6 million, respectively, for 2006 and totaled approximately $82.1 million, $81.7 million, and $18.4 million, respectively, for 2005.
In October 2006, the Mississippi PSC issued a financing order that authorized the issuance of $121.2 million of system restoration bonds. This amount includes $25.2 million for the retail storm recovery costs not covered by the CDBG, $60 million for a property damage reserve, and $36 million for the retail portion of the construction of the storm operations facility. The storm restoration bonds were issued by the Mississippi Development Bank on June 1, 2007, on behalf of the State of Mississippi. On June 1, 2007, the Company received a grant payment of $85.2 million from the State of Mississippi representing recovery of $25.2 million in retail storm restoration costs incurred or to be incurred and $60.0 million to increase Mississippi Power’s property damage reserve. In the fourth quarter of 2007, the Company received two additional grant payments totaling $24.1 million for expenditures incurred for construction of a new storm operations center. The funds received related to previously incurred storm restoration expenditures have been accounted for as a government grant and have been recorded as a reduction to the regulatory asset that was recorded as the storm restoration expenditures were incurred. The funds received for storm restoration expenditures to be incurred were recorded as a regulatory liability. The Company will receive further grant payments of up to $11.9 million as expenditures are incurred to construct the new storm operations center.
The funds received with respect to certain of the grants were funded through the Mississippi Development Bank’s issuance of tax-exempt bonds. Due to the tax-exempt status to the holders of bonds for federal income tax purposes, the use of the proceeds is limited to expenditures that qualify under the Internal Revenue Code of 1986, as amended (Internal Revenue Code). Prior to the receipt of the proceeds from the tax-exempt bonds in 2007, management of the Company represented to the Mississippi Development Bank that all expenditures to date qualify under the Internal Revenue Code. Should the Company use the proceeds for non-qualifying expenditures, it could be required to return that portion of the proceeds received from the tax-exempt bond issuance that was applied to non-qualifying expenditures. Management expects that all future expenditures will also qualify and that no proceeds will be required to be returned.
In order for the State of Mississippi to repay the bonds issued by the Mississippi Development Bank, the State of Mississippi has established a system restoration charge that will be charged to all retail electric utility customers within the Company’s service area. This charge will be collected by the Company through the retail customers’ monthly statement and remitted to the State of Mississippi
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on a monthly basis. The system restoration charge is the property of the State of Mississippi. The Company’s only obligation is to collect and remit the proceeds of the charge. The Company began collecting the system restoration charge on June 20, 2007, and remitted the first payment to the State of Mississippi on July 17, 2007.
The Company incurred the $302.4 million total storm costs affirmed by the Mississippi PSC as of December 31, 2007. The balance in the retail regulatory liability account at December 31, 2007, was $0.1 million, which is net of the retail portion of insurance proceeds of $78.1 million, CDBG proceeds of $267.6 million, storm restoration bond proceeds of $25.1 million, and tax credits of $0.3 million. Retail costs incurred through December 31, 2007, include approximately $158.5 million of capital and $134.4 million of operations and maintenance expenditures. The Company will report the regulatory liability balance to the Mississippi PSC to determine the final disposition of this balance.
In June 2006, the Mississippi PSC order also granted continuing authority to record a regulatory asset in an amount equal to the retail portion of the recorded Hurricane Katrina restoration costs. For any future event causing damage to property beyond the balance in the reserve, the order also granted the Company the authority to record a regulatory asset. The Company would then apply to the Mississippi PSC for recovery of such amounts or for authority to otherwise dispose of the regulatory asset. The Company continues to report actual storm expenses to the Mississippi PSC periodically.
See Note 1 to the financial statements under “Provision for Property Damage” for additional information.
Income Tax Matters
Internal Revenue Code Section 199 Domestic Production Deduction
The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in the Internal Revenue Code Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for years 2007 through 2009, and a 9% rate applicable for all years after 2009. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.
Bonus Depreciation
On February 13, 2008, President Bush signed the Economic Stimulus Act of 2008 (Stimulus Act) into law. The Stimulus Act includes a provision that allows 50% bonus depreciation for certain property acquired in 2008 and placed in service in 2008 or, in certain limited cases, 2009. The Company is currently assessing the financial implications of the Stimulus Act; however, the ultimate impact cannot be determined at this time.
Construction Projects
In June 2006, the Company filed an application with the U.S. Department of Energy (DOE) for certain tax credits available to projects using clean coal technologies under the Energy Policy Act of 2005. The proposed project is an advanced coal gasification facility located in Kemper County, Mississippi, that would use locally mined lignite coal. The proposed 693 megawatt plant is expected to require an approximate investment of $1.5 billion, excluding the mine cost, and is expected to be completed in 2013. The DOE subsequently certified the project and in November 2006, the Internal Revenue Service (IRS) allocated Internal Revenue Code Section 48A tax credits of $133 million to the Company. The utilization of these credits is dependent upon meeting the certification requirements for the project. The plant would use an air-blown integrated gasification combined cycle technology that generates power from low-rank coals and coals with high moisture or high ash content. These coals, which include lignite, make up half the proven U.S. and worldwide coal reserves. The Company is undertaking a feasibility assessment of the project, which could take up to two years. On December 21, 2006, the Mississippi PSC approved the Company’s request for accounting treatment of the costs associated with the Company’s generation resource planning, evaluation, and screening activities. The Mississippi PSC gave the Company the authority to create and recognize a regulatory asset for such costs. On December 28, 2007, the Company received an order allowing it to defer the amortization of these costs to January 2009. In addition, Mississippi received approval for the updated estimate of approximately $23.8 million in total generation screening and evaluation costs ($16 million for the retail portion). At December 31, 2007, the Company had spent $18.1 million in total, of which $2.7 million related to land purchases was capitalized, the retail portion of $11.2 million was deferred in other regulatory assets, and the wholesale portion of $4.2 million was expensed. The retail portion of these costs will be charged to and remain as a regulatory asset until the Mississippi PSC determines the prudence and ultimate recovery of such costs, which decision is expected in January 2009. The balance of such regulatory asset will be included in
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the Company’s rate base for ratemaking purposes. Approval by various regulatory agencies, including the Mississippi PSC, will also be required if the project proceeds. The final outcome of this matter cannot now be determined.
Other Matters
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. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements. See Note 3 to the financial statements for information regarding material issues.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed critical accounting policies and estimates described below with the Audit Committee of Southern Company’s Board of Directors.
Electric Utility Regulation
The Company is subject to retail regulation by the Mississippi PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies Financial Accounting Standards Board (FASB) Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), which requires the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of SFAS No. 71 has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and postretirement benefits have less of a direct impact on the Company’s results of operations than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines and accounting principles generally accepted in the United States. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s financial statements.
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a loss is considered probable and reasonably estimable in accordance with generally accepted accounting principles. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company’s financial statements. These events or conditions include the following:
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•
Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances, hazardous and solid wastes, and other environmental matters;
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Changes in existing income tax regulations or changes in IRS or state revenue department interpretations of existing regulations;
•
Identification of additional sites that require environmental remediation or the filing of other complaints in which the Company may be asserted to be a potentially responsible party;
•
Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant; and
•
Resolution or progression of existing matters through the legislative process, the court systems, the IRS, the FERC, or the EPA.
Unbilled Revenues
Revenues related to the sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, and power delivery volume and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company’s results of operations.
Plant Daniel Operating Lease
As discussed in Note 7 to the financial statements under “Operating Leases - Plant Daniel Combined Cycle Generating Units,” the Company leases a 1,064 megawatt natural gas combined cycle facility at Plant Daniel (Facility) from Juniper Capital L.P. (Juniper). For both accounting and rate recovery purposes, this transaction is treated as an operating lease, which means that the related obligations under this agreement are not reflected in the balance sheets. See FINANCIAL CONDITION AND LIQUIDITY - “Off-Balance Sheet Financing Arrangements” herein for further information. The operating lease determination was based on assumptions and estimates related to the following:
•
Fair market value of the Facility at lease inception;
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The Company’s incremental borrowing rate;
•
Timing of debt payments and the related amortization of the initial acquisition cost during the initial lease term;
•
Residual value of the Facility at the end of the lease term;
•
Estimated economic life of the Facility; and
•
Juniper’s status as a voting interest entity.
The determination of operating lease treatment was made at the inception of the lease agreement and is not subject to change unless subsequent changes are made to the agreement. However the Company also is required to monitor Juniper’s ongoing status as a voting interest entity. Changes in that status could require the Company to consolidate the Facility’s assets and the related debt and to record interest and depreciation expense of approximately $37 million annually, rather than annual lease expense of approximately $27 million.
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New Accounting Standards
Income Taxes
On January 1, 2007, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), which requires companies to determine whether it is “more likely than not” that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. It also provides guidance on the recognition, measurement, and classification of income tax uncertainties, along with any related interest and penalties. The provisions of FIN 48 were applied to all tax positions beginning January 1, 2007. The adoption of FIN 48 did not have a material impact on the Company’s financial statements. See Note 5 to the financial statements for additional information.
Pensions and Other Postretirement Plans
On December 31, 2006, the Company adopted FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS No. 158), which requires recognition of the funded status of its defined benefit postretirement plans in the balance sheets. Additionally, SFAS No. 158 will require the Company to change the measurement date for its defined benefit postretirement plan assets and obligations from September 30 to December 31 beginning with the year ending December 31, 2008. See Note 2 to the financial statements for additional information.
Fair Value Measurement
The FASB issued FASB Statement No. 157, “Fair Value Measurements” (SFAS No. 157), in September 2006. SFAS No. 157 provides guidance on how to measure fair value where it is permitted or required under other accounting pronouncements. SFAS No. 157 also requires additional disclosures about fair value measurements. The Company adopted SFAS No. 157 in its entirety on January 1, 2008, with no material effect on its financial condition or results of operations.
Fair Value Option
In February 2007, the FASB issued FASB Statement No. 159, “Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115” (SFAS No. 159). This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. The Company adopted SFAS No. 159 on January 1, 2008, with no material effect on its financial condition or results of operations.
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company’s financial condition remained stable at December 31, 2007. Net cash flow from operating activities increased from 2006 by $11.7 million. The increase in operating activities was primarily due to the decrease in the use of funds related to Hurricane Katrina accounts payable in 2007 by $50.5 million related to cash outflows for restoration costs in 2006. Also impacting operating activities were decreases in uses of funds related to other accounts payable and over recovered regulatory clause revenues of $25.9 million and $26.2 million, respectively. The Company received $74.3 million in bond proceeds during 2007 related to Hurricane Katrina recovery, of which $60 million is being used to fund the property damage reserve and $14.3 million to recover retail operations and maintenance storm restoration cost. A $39.9 million decrease in operating activities related to receivables is primarily due to a $36 million decrease in external insurance proceeds received in 2007 as compared to 2006 related to Hurricane Katrina. The $153.0 million increase in net cash from operating activities for 2006 compared to 2005 resulted primarily from $120.3 million received from the CDBG program. In 2005, net cash flow from operating activities decreased $77.4 million when compared to 2004 primarily due to the storm damage costs related to Hurricane Katrina. The change in net cash used for investing activities in 2007 compared to 2006 of $107.0 million was primarily due to a $117.8 million reduction in the source of funds related to Hurricane Katrina capital related grant and bond proceeds. Net cash used for financing activities totaled $105.5 million in 2007 compared to $211.5 million in 2006. This decrease in net cash used for financing activities is primarily due to a decrease in the use of funds related to notes payable of $109.3 million. See FUTURE EARNINGS POTENTIAL - “PSC Matters - Storm Damage Cost Recovery” for additional information.
Significant changes in the balance sheet as of December 31, 2007, compared to 2006, primarily relate to both normal business activities as well as Hurricane Katrina storm restoration activities. These activities include an increase in property, plant and
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2007 Annual Report
equipment of $42.9 million as well as an increase in prepaid pension costs in 2007 as compared to 2006 in the amount of $29.7 million. These increases in assets were offset by a $20.6 million decrease in insurance receivable primarily as a result of the receipt of external insurance proceeds related to Hurricane Katrina. These activities also include a decrease in notes payable of $41.4 million and an increase in other regulatory liabilities in 2007 as compared to 2006 in the amount of $96.9 million, of which $60.0 million related to the receipt of bond proceeds from the State of Mississippi to replenish the property damage reserve, as well as an increase of $32.1 million related to an additional liability resulting from the adoption of SFAS No. 158. For additional information regarding significant changes in the balance sheets, see Note 2 to the financial statements under “Retirement Benefits.” See FUTURE EARNINGS POTENTIAL - “PSC Matters - Storm Damage Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters - Storm Damage Recovery” for additional information related to the deferral of the restoration costs, including both capital and operation and maintenance expenditures.
The Company’s ratio of common equity to total capitalization, excluding long-term debt due within one year, increased from 65.4% in 2006 to 66.1% at December 31, 2007. The Company has received investment grade ratings from the major rating agencies with respect to debt, preferred securities, and preferred stock.
Sources of Capital
The Company plans to obtain the funds required for construction, continued storm damage restoration, and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, security issuances, term loans, and short-term borrowings. See Note 3 to the financial statements under “Storm Damage Cost Recovery” for additional information. The amount, type, and timing of any financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors.
The issuance of securities by the Company is subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933, as amended (1933 Act). The amount of securities authorized by the FERC, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.
The Company obtains financing separately without credit support from any affiliate. 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.
To meet short-term cash needs and contingencies, the Company has various sources of liquidity. At December 31, 2007, the Company had approximately $4.8 million of cash and cash equivalents and $181 million of unused credit arrangements with banks. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.
The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other traditional operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other traditional operating company. The obligations of each company under these arrangements are several; there is no cross affiliate credit support. At December 31, 2007, the Company had $9.9 million of commercial paper outstanding.
Financing Activities
In the fourth quarter of 2007, the Company issued senior notes totaling $35 million. Proceeds were used to repay a portion of the Company’s short-term indebtedness.
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.
Off-Balance Sheet Financing Arrangements
In 2001, the Company began an initial 10-year term of a lease agreement for a combined cycle generating facility built at Plant Daniel. In June 2003, the Company entered into a restructured lease agreement for the Facility with Juniper, as discussed in Note 7 to the financial statements under “Operating Leases - Plant Daniel Combined Cycle Generating Units.” Juniper has also entered into leases with other parties unrelated to the Company. The assets leased by the Company comprise less than 50% of Juniper’s assets. The
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2007 Annual Report
Company does not consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease. Accordingly, the lease is not reflected in the balance sheets.
The initial lease term ends in 2011, and the lease includes a renewal and a purchase option based on the cost of the Facility at the inception of the lease, which was approximately $370 million. The Company is required to amortize approximately 4% of the initial acquisition cost over the initial lease term. Eighteen months prior to the end of the initial lease, the Company may elect to renew for 10 years. If the lease is renewed, the agreement calls for the Company to amortize an additional 17% of the initial completion cost over the renewal period. Upon termination of the lease, at the Company’s option, it may either exercise its purchase option or the Facility can be sold to a third party.
The lease also provides for a residual value guarantee, approximately 73% of the acquisition cost, by the Company that is due upon termination of the lease in the event that the Company does not renew the lease or purchase the Facility and that the fair market value is less than the unamortized cost of the Facility.
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- or Baa3. These contracts are primarily for electricity sales and coal purchases. At December 31, 2007, the maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $8 million. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash.
The Company, along with all members of the Southern Company power pool, is party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade for Alabama Power and/or Georgia Power. These agreements are primarily for natural gas and power price risk management activities. At December 31, 2007, the Company’s total exposure to these types of agreements was approximately $15 million.
Market Price Risk
Due to cost-based rate regulation, the Company has limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and hedging practices. Company policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques that include, but are not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
The Company does not currently hedge interest rate risk. The weighted average interest rate on $122.7 million of variable long-term debt at January 1, 2008 was 4.38%. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $1.2 million at December 31, 2007. See Notes 1 and 6 to the financial statements under “Financial Instruments” for additional information.
To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. At December 31, 2007, exposure from these activities was not material to the Company’s financial statements.
Of the Company’s $122.7 million of variable interest rate exposure, approximately $43 million relates to tax-exempt auction rate pollution control bonds. Recent weakness in the auction markets has resulted in higher interest rates. The Company plans to convert the series to a fixed interest rate determination method and plans to remarket all remaining auction rate securities in a timely manner. None of the securities are insured or backed by letters of credit that would require approval of a guarantor or security provider. It is not expected that the higher rates as a result of the weakness in the auction markets will be material.
In addition, at the instruction of the Mississippi PSC, the Company has implemented a fuel-hedging program. At December 31, 2007, exposure from these activities was not material to the Company’s financial statements.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2007 Annual Report
The changes in fair value of energy contracts and year-end valuations were as follows:
(a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
These contracts are related primarily to fuel hedging programs under which unrealized gains and losses from mark to market adjustments are recorded as regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are recovered through the Company’s energy cost management clause.
Gains and losses on forward contracts for the sale of electricity that do not represent hedges are recognized in the statements of income as incurred. For the years ended December 31, 2007, 2006, and 2005, these amounts were not material.
At December 31, 2007, the fair value gains/(losses) of energy-related derivative contracts were reflected in the financial statements as follows:
Unrealized pre-tax gains and losses from energy-related derivative contracts recognized in income were not material for any year presented. The Company is exposed to market price risk in the event of nonperformance by counterparties to the energy-related derivative contracts. The Company’s policy is to enter into agreements with counterparties that have investment grade credit ratings by Moody’s and Standard & Poor’s or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. See Notes 1 and 6 to the financial statements under “Financial Instruments” for additional information.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2007 Annual Report
Capital Requirements and Contractual Obligations
The construction program of the Company is currently estimated to be $186 million for 2008, of which $8 million is related to Hurricane Katrina restoration, $226 million for 2009, and $211 million for 2010. Environmental expenditures included in these estimated amounts are $74.4 million, $128.2 million, and $91.9 million for 2008, 2009, and 2010, respectively. Actual construction costs may vary from these estimates because of changes in such factors as: business conditions; environmental statutes and regulations; FERC rules and regulations; load projections; storm impacts; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
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 FERC.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred stock dividends, leases, and other purchase commitments, are as follows. See Notes 1, 6, and 7 to the financial statements for additional information.
Contractual Obligations
(a)
All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2008, as reflected in the statements of capitalization.
(b)
Preferred stock does not mature; therefore, amounts are provided for the next five years only.
(c)
For additional information, see Notes 1 and 6 to the financial statements.
(d)
The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for 2007, 2006, and 2005 were $255 million, $237 million, and $240 million, respectively.
(e)
The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures. At December 31, 2007, significant purchase commitments were outstanding in connection with the construction program.
(f)
Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2007.
(g)
Long-term service agreements include price escalation based on inflation indices.
(h)
The Company forecasts postretirement benefits trust contributions over a three-year period. No contributions related to the Company’s pension trust are currently expected during this period. See Note 2 to the financial statements for additional information related to the pension and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2007 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company’s 2007 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning growth, retail rates, storm damage cost recovery and repairs, fuel cost recovery, environmental regulations and expenditures, access to sources of capital, projections for postretirement benefit trust contributions, financing activities, impacts of the adoption of new accounting rules, completion of construction projects, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized.
These factors include:
•
the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, or particulate matter and other substances and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
•
current and future litigation, regulatory investigations, proceedings, or inquiries, including FERC matters and EPA civil actions;
•
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
•
variations in demand for electricity, including those relating to weather, the general economy, population and business growth (and declines), and the effects of energy conservation measures;
•
available sources and costs of fuel;
•
effects of inflation;
•
ability to control costs;
•
investment performance of the Company’s employee benefit plans;
•
advances in technology;
•
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and storm restoration cost recovery;
•
internal restructuring or other restructuring options that may be pursued;
•
potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;
•
the ability of counterparties of the Company to make payments as and when due;
•
the ability to obtain new short- and long-term contracts with neighboring utilities;
•
the direct or indirect effect on the Company’s business resulting from terrorist incidents and the threat of terrorist incidents;
•
interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company’s credit ratings;
•
the ability of the Company to obtain additional generating capacity at competitive prices;
•
catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as an avian influenza, or other similar occurrences;
•
the direct or indirect effects on the Company’s business resulting from incidents similar to the August 2003 power outage in the Northeast;
•
the effect of accounting pronouncements issued periodically by standard setting bodies; and
•
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
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STATEMENTS OF INCOME
For the Years Ended December 31, 2007, 2006, and 2005
Mississippi Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2007, 2006, and 2005
Mississippi Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2007 and 2006
Mississippi Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2007 and 2006
Mississippi Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF CAPITALIZATION
At December 31, 2007 and 2006
Mississippi Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2007, 2006, and 2005
Mississippi Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2007, 2006, and 2005
Mississippi Power Company 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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NOTES TO FINANCIAL STATEMENTS
Mississippi Power Company 2007 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Mississippi Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies, Alabama Power, Georgia Power, Gulf Power, and the Company, provide electric service in four Southeastern states. The Company operates as a vertically integrated utility providing service to retail customers in southeast Mississippi and to wholesale customers in the Southeast. Southern Power constructs, acquires, and manages generation assets, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications services to the traditional operating companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy- related businesses. The investments in synthetic fuels ended on December 31, 2007. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants.
The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities where the Company is not the primary beneficiary.
The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC) and the Mississippi Public Service Commission (PSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from those estimates.
Reclassifications
Certain prior years’ data presented in the financial statements have been reclassified to conform with current year presentation. These reclassifications had no effect on total assets, net income, or cash flows.
The balance sheets and statements of cash flows have been modified to combine “Long-term Debt Payable to Affiliated Trust” into “Long-term Debt.” Correspondingly, the statements of income were modified to report “Interest expense to affiliate trust” together with “Interest expense, net of amounts capitalized.”
Affiliate Transactions
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, purchasing, accounting and statistical analysis, finance and treasury, tax, information resources, marketing, auditing, insurance and pension administration, human resources, systems and procedures, and other services with respect to business and operations and power pool transactions. Costs for these services amounted to $71.8 million, $55.2 million, and $51.6 million during 2007, 2006, and 2005, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.
The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. However, with the hurricane damage experienced in recent years, assistance for storm restoration has caused an increase in these activities. The total amount of storm restoration provided to Alabama Power, Georgia Power, and Gulf Power in 2005 was $1.0 million. These activities were billed at cost. The Company received storm restoration assistance from other Southern Company subsidiaries totaling $1.5 million and $73.5 million in 2006 and 2005, respectively.
The Company has an agreement with Alabama Power under which the Company owns a portion of Greene County Steam Plant. Alabama Power operates Greene County Steam Plant, and the Company reimburses Alabama Power for its proportionate share of all associated expenditures and costs. The Company reimbursed Alabama Power for the Company’s proportionate share of related expenses which totaled $9.8 million, $8.6 million, and $8.2 million in 2007, 2006, and 2005, respectively. The Company also has an
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NOTES (continued)
Mississippi Power Company 2007 Annual Report
agreement with Gulf Power under which Gulf Power owns a portion of Plant Daniel. The Company operates Plant Daniel, and Gulf Power reimburses the Company for its proportionate share of all associated expenditures and costs. Gulf Power reimbursed the Company for Gulf Power’s proportionate share of related expenses which totaled $23.1 million, $19.7 million, and $19.5 million in 2007, 2006, and 2005, respectively. See Notes 4 and 5 for additional information on certain deferred tax liabilities payable to affiliates.
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 Commitments” for additional information.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
Note:
The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
(a)
For additional information, see Note 3 under “Retail Regulatory Matters - Storm Damage Cost Recovery.”
(b)
Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 under “Retirement Benefits.”
(c)
Recorded and recovered as approved by the Mississippi PSC.
(d)
Asset retirement and removal liabilities are recorded, deferred income tax assets are recovered and deferred tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.
(e)
Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year.
(f)
Amortized over a four-year period ending 2011.
(g)
Recorded as earned by employees and recovered as paid, generally within one year.
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NOTES (continued)
Mississippi Power Company 2007 Annual Report
(h)
Recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 50 years.
(i)
Amortized over a period beginning in 2004 that is not to exceed seven years.
(j)
Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, costs are recovered through the Energy Cost Management clause (ECM).
(k)
Amortized over a four-year period which ended in 2007.
In the event that a portion of the Company’s operations is no longer subject to the provisions of SFAS No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under “Retail Regulatory Matters - Storm Damage Cost Recovery.”
Government Grants
The Company received a grant in October 2006 from the Mississippi Development Authority (MDA) for $276.4 million, primarily for storm damage cost recovery. On June 1, 2007, the Company received a grant payment of $85.2 million from the State of Mississippi related to storm restoration costs to be incurred and to increase the property damage reserve. In the fourth quarter 2007, the Company received additional grant payments totaling $24.1 million for expenditures incurred to date for construction of a new storm operations center. The grant proceeds do not represent a future obligation of the Company. The portion of any grants received related to retail storm recovery is applied to the retail regulatory asset that is established as restoration costs are incurred. The portion related to wholesale storm recovery is recorded either as a reduction to operations and maintenance expense or as a reduction in accumulated depreciation depending on the restoration work performed and the appropriate allocations of cost of service.
Revenues
Energy and other revenues are recognized as services are rendered. Wholesale capacity revenues from long-term contracts are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract period. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. The Company’s retail and wholesale rates include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Retail rates also include provisions to adjust billings for fluctuations in costs for ad valorem taxes and certain qualifying environmental 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 is required to file with the Mississippi PSC for an adjustment to the fuel cost recovery factor annually.
The Company has a diversified base of customers. For years ended December 31, 2007, and December 31, 2006, no single customer or industry comprises 10% or more of revenue. 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 the cost of purchased emission allowances as they are used. Fuel costs also included gains and/or losses from fuel hedging programs as approved by the Mississippi PSC.
Income and Other Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.
In accordance with FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), the Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information on the effect of adopting FIN 48.
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NOTES (continued)
Mississippi Power Company 2007 Annual Report
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction for projects over $10 million.
The Company’s property, plant, and equipment consisted of the following at December 31:
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense except for the cost of maintenance of coal cars and a portion of the railway track maintenance costs, which are charged to fuel stock and recovered through the Company’s fuel clause.
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.3%, 3.2%, and 3.4% in 2007, 2006, and 2005, respectively. Depreciation studies are conducted periodically to update the composite rates. In March 2006, the Mississippi PSC approved the study filed by the Company in 2005, with new rates effective January 1, 2006. The new depreciation rates did not result in a material change to annual depreciation expense. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost, together with the cost of removal, less salvage, is charged to the accumulated depreciation provision. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation expense includes an amount for the expected cost of removal of facilities.
In January 2006, the Mississippi PSC issued an accounting order directing the Company to exclude from its calculation of depreciation expense approximately $1.2 million related to capitalized Hurricane Katrina costs since these costs will be recovered separately.
In December 2003, the Mississippi PSC issued an interim accounting order directing the Company to expense and record a regulatory liability of $60.3 million while it considered the Company’s request to include 266 megawatts of Plant Daniel Units 3 and 4 generating capacity in jurisdictional cost of service. In May 2004, the Mississippi PSC approved the Company’s request effective January 1, 2004, and ordered the Company to amortize the regulatory liability previously established to reduce depreciation and amortization expenses as follows: $16.5 million in 2004, $25.1 million in 2005, $13.0 million in 2006, and $5.7 million in 2007.
Asset Retirement Obligations and Other Costs of Removal
Asset retirement obligations are computed as the present value of the ultimate costs for an asset’s future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. The Company has received accounting guidance from the Mississippi PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations will continue to be reflected in the balance sheets as a regulatory liability.
The Company has retirement obligations related to various landfill sites and underground storage tanks. In connection with the adoption of FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), the Company also recorded additional asset retirement obligations (and assets) of $9.5 million, primarily related to asbestos. The Company also has identified retirement obligations related to certain transmission and distribution facilities, co-generation facilities, certain wireless communication towers, and certain structures authorized by the United States Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized under FASB Statement No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143) and FIN 47 and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Mississippi PSC, and are reflected in the balance sheets.
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Details of the asset retirement obligations included in the balance sheets are as follows:
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 asset and recording a loss for the amount 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.
Provision for Property Damage
The Company carries insurance for the cost of certain types of damage to generation plants and general property. However, the Company is self-insured for the cost of storm, fire, and other uninsured casualty damage to its property, including transmission and distribution facilities. As permitted by the Mississippi PSC and the FERC, the Company accrues for the cost of such damage through an annual expense accrual credited to a regulatory liability account. The cost of repairing actual damage resulting from such events that individually exceed $50,000 is charged to the reserve. A 1999 Mississippi PSC order allowed the Company to accrue $1.5 million to $4.6 million to the reserve annually, with a maximum reserve totaling $23 million. In October 2006, in conjunction with the Mississippi PSC Hurricane Katrina-related financing order, the Mississippi PSC ordered the Company to cease all accruals to the retail property damage reserve until a new reserve cap is established. However, in the same financing order, the Mississippi PSC approved the replenishment of the property damage reserve with $60 million to be funded with a portion of the proceeds of bonds to be issued by the Mississippi Development Bank on behalf of the State of Mississippi and reported as liabilities by the State of Mississippi. The Company received the $60 million bond proceeds in June 2007. The Company accrued $0.2 million in 2007, $1.2 million in 2006, and $1.5 million in 2005. The Company made no discretionary accruals in 2007 and 2006 as a result of the order. See Note 3 under “Storm Damage Cost Recovery” and “System Restoration Rider” for additional information regarding the depletion of these reserves following Hurricane Katrina and the deferral of additional costs, as well as additional rate riders or other cost recovery mechanisms which have and/or may be approved by the Mississippi PSC to recover the deferred costs and accrue reserves.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed or used.
Fuel Inventory
Fuel inventory includes the average costs of oil, coal, natural gas, and emission allowances. Fuel is charged to inventory when purchased and then expensed as used and recovered by the Company through fuel cost recovery rates approved by the Mississippi PSC. Emission allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.
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Stock Options
Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. Prior to January 1, 2006, the Company accounted for options granted in accordance with Accounting Principles Board Opinion No. 25; thus, no compensation expense was recognized because the exercise price of all options granted equaled the fair market value on the date of the grant.
Effective January 1, 2006, the Company adopted the fair value recognition provisions of FASB Statement No. 123(R), “Share-Based Payment” (SFAS No. 123(R)), using the modified prospective method. Under that method, compensation cost for the years ended December 31, 2007 and 2006, was recognized as the requisite service was rendered and included: (a) compensation cost for the portion of share-based awards granted prior to and that were outstanding as of January 1, 2006, for which the requisite service had not been rendered, based on the grant-date fair value of those awards as calculated in accordance with the original provisions of FASB Statement No. 123, “Accounting for Stock-Based Compensation,” and (b) compensation cost for all share-based awards granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123(R). Results for prior periods have not been restated.
The compensation cost and tax benefits related to the grant and exercise of Southern Company stock options to the Company’s employees are recognized in the Company’s financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company.
For the Company, the adoption of SFAS No. 123(R) resulted in a reduction in earnings before income taxes and net income of $1.0 million and $0.6 million, respectively, for the year ended December 31, 2007, and $1.1 million and $0.7 million, respectively, for the year ended December 31, 2006. Additionally, SFAS No. 123(R) requires the gross excess tax benefit from stock option exercises to be reclassified as a financing cash flow as opposed to an operating cash flow; the reduction in operating cash flows and the increase in financing cash flows for the years ended December 31, 2007 and 2006, was $0.6 and $0.7 million, respectively.
For the year ended December 31, 2005, prior to the adoption of SFAS No. 123(R), the pro forma impact on net income of fair-value accounting for options granted on net income was as follows:
Because historical forfeitures have been insignificant and are expected to remain insignificant, no forfeitures were assumed in the calculation of compensation expense; rather they are recognized when they occur.
The estimated fair values of stock options granted in 2007, 2006, and 2005 were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company’s stock over a period equal to the expected term. The Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options.
The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted:
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in the prices of certain fuel purchases and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities and are measured at
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fair value. Substantially all of the Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are exempt from fair value accounting requirements and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the Mississippi PSC approved fuel hedging program as discussed below. This results in the deferral of related gains and losses in other comprehensive income or regulatory assets and liabilities, respectively, as appropriate until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income.
The Mississippi PSC has approved the Company’s request to implement an ECM which, among other things, allows the Company to utilize financial instruments to hedge its fuel commitments. Changes in the fair value of these financial instruments are recorded as regulatory assets or liabilities. Amounts paid or received as a result of financial settlement of these instruments are classified as fuel expense and are included in the ECM factor applied to customer billings. The Company’s jurisdictional wholesale customers have a similar ECM mechanism, which has been approved by the FERC.
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.
Other financial instruments for which the carrying amounts did not equal the fair values at December 31 were as follows:
The fair values were based on either closing market prices or closing prices of comparable instruments.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and prior to the adoption of SFAS No.158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS No. 158) the minimum pension liability, less income taxes and reclassifications for amounts included in net income.
Variable Interest Entities
The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. The Company has established a wholly-owned trust to issue preferred securities. See Note 6 under “Long-Term Debt Payable to Affiliated Trust” for additional information. However, the Company is not considered the primary beneficiary of the trust. Therefore, the investments in this trust are reflected as Other Investments and the related loan from the trust is included in Long-term Debt in the balance sheets. During 2007 the Company redeemed its last remaining series of preferred securities, which totaled $36 million.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the plan are expected for the year ending December 31, 2008. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds related trusts to the extent required by the FERC. For the year ending December 31, 2008, postretirement trust contributions are expected to total approximately $0.2 million.
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The measurement date for plan assets and obligations is September 30 for each year presented. Pursuant to SFAS No. 158, the Company will be required to change the measurement date for its defined benefit postretirement plans from September 30 to December 31 beginning with the year ending December 31, 2008.
Pension Plans
The total accumulated benefit obligation for the pension plans was $240 million and $233 million for 2007 and 2006, respectively. Changes during the year in the projected benefit obligations and fair value of plan assets were as follows:
At December 31, 2007, the projected benefit obligations for the qualified and non-qualified pension plans were $234.8 million and $22.1 million, respectively. All plan assets are related to the qualified pension plan.
Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk. The actual composition of the Company’s pension plan assets as of the end of the year, along with the targeted mix of assets, is presented below:
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Amounts recognized in the balance sheets related to the Company’s pension plan consist of the following:
Presented below are the amounts included in regulatory assets and regulatory liabilities at December 31, 2007 and December 31, 2006, related to the defined benefit pension plans that have not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for the next fiscal year.
The changes in the balances of regulatory assets and regulatory liabilities related to the defined benefit pension plans for the year ended December 31, 2007, are presented in the following table:
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Components of net periodic pension cost (income) were as follows:
Net periodic pension cost (income) is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2007, estimated benefit payments were as follows:
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Other Postretirement Benefits
Changes during the year in the accumulated postretirement benefit obligations (APBO) and in the fair value of plan assets were as follows:
Other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk. The actual composition of the Company’s other postretirement benefit plan assets as of the end of the year, along with the targeted mix of assets, is presented below:
Amounts recognized in the balance sheets related to the Company’s other postretirement benefit plans consist of the following:
Presented below are the amounts included in regulatory assets at December 31, 2007 and December 31, 2006, related to the other postretirement benefit plans that have not yet been recognized in net periodic postretirement benefit cost along with the estimated amortization of such amounts for 2008.
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The change in the balance of regulatory assets related to the postretirement benefit plans for the year ended December 31, 2007, is presented in the following table:
Components of the other postretirement benefit plans’ net periodic cost were as follows:
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced the Company’s expenses for the years ended December 31, 2007, 2006, and 2005 by approximately $1.8 million, $2.0 million, and $1.2 million, respectively.
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the postretirement plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows:
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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 2004 for the 2005 plan year using a discount rate of 5.75%.
The Company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.
An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 9.75% for 2008, decreasing gradually to 5.25% through the year 2015, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2007 as follows:
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution up to 6% of an employee’s base salary. Prior to November 2006, the Company matched employee contributions at a rate of 75% up to 6% of the employee’s base salary. Total matching contributions made to the plan for 2007, 2006, and 2005 were $3.5 million, $3.0 million, and $2.9 million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements.
Environmental Matters
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama after Alabama Power was dismissed from the original action. In these lawsuits, the EPA alleged that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including one co-owned by the Company. The civil actions request penalties and injunctive relief, including an order requiring the
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installation of the best available control technology at the affected units. The action against Georgia Power has been administratively closed since the spring of 2001, and the case has not been reopened.
In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving the alleged NSR violations at Plant Miller. The consent decree required Alabama Power to pay $100,000 to resolve the government’s claim for a civil penalty and to donate $4.9 million of sulfur dioxide emission allowances to a nonprofit charitable organization and formalized specific emissions reductions to be accomplished by Alabama Power, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in Alabama granted Alabama Power’s motion for summary judgment and entered final judgment in favor of Alabama Power on the EPA’s claims related to all of the remaining plants: Plants Barry, Gaston, Gorgas, and Greene County.
The plaintiffs appealed the district court’s decision to the U.S. Court of Appeals for the Eleventh Circuit, and the appeal was stayed by the Appeals Court pending the U.S. Supreme Court’s decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke Energy case in April 2007. On October 5, 2007, the U.S. District Court for the Northern District of Alabama issued an order in the Alabama Power case indicating a willingness to re-evaluate its previous decision in light of the Supreme Court’s Duke Energy opinion. On December 21, 2007, the Eleventh Circuit vacated the district court’s decision in the Alabama Power case and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court’s decision in the Duke Energy case.
The Company believes it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in either of these cases could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
Carbon Dioxide Litigation
In July 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and no decision has been issued. The ultimate outcome of these matters cannot be determined at this time.
Environmental Remediation
The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. The Company has authority from the Mississippi PSC to recover approved environmental compliance costs through regulatory mechanisms.
In 2003, the Texas Commission on Environmental Quality (TCEQ) designated the Company as a potentially responsible party at a site in Texas. The site was owned by an electric transformer company that handled the Company’s transformers as well as those of many other entities. The site owner is now in bankruptcy and the State of Texas has entered into an agreement with the Company and several other utilities to investigate and remediate the site. Amounts expensed during 2005, 2006, and 2007 related to this work were not material. Hundreds of entities have received notices from the TCEQ requesting their participation in the anticipated site remediation. The final outcome of this matter to the Company will depend upon further environmental assessment and the ultimate number of potentially responsible parties and cannot now be determined. The remediation expenses incurred by the Company are
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expected to be recovered through the Environmental Compliance Overview (ECO) Plan. See “Retail Regulatory Matters -Environmental Compliance Overview Plan” herein for additional information.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.
In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales by the Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level.
In late June and July 2007, hearings were held in this proceeding and the presiding administrative law judge issued an initial decision on November 9, 2007 regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the Company to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates, and could also result in refunds of up to $8.4 million, plus interest. The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter.
On June 21, 2007, the FERC issued its final rule regarding market-based rate authority. The FERC generally retained its current market-based rate standards. The impact of this order and its effect on the generation dominance proceeding cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet is operated under the Intercompany Interchange Contract (IIC), as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies (including the Company), Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct.
In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms and Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. Southern Company filed with the FERC in November 2006 a compliance plan in connection with the order. On April 19, 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan is not expected to have a material impact on the Company’s financial statements. On November 19, 2007, Southern Company notified the FERC that the plan had been implemented and the FERC division of audits subsequently began an audit pertaining to compliance implementation and related matters, which is ongoing.
Right of Way Litigation
Southern Company and certain of its subsidiaries, including the Company, Gulf Power, and Southern Telecom, Inc., (a subsidiary of SouthernLINC Wireless), have been named as defendants in numerous lawsuits brought by landowners since 2001. The plaintiffs’ lawsuits claim that defendants may not use, or sublease to third parties, some or all of the fiber optic communications lines on the rights of way that cross the plaintiffs’ properties and that such actions exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment and seek compensatory and punitive damages and injunctive relief. Management of the Company believes that it has complied with applicable laws and that the plaintiffs’ claims are without merit.
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To date, the Company has entered into agreements with plaintiffs in approximately 90% of the actions pending against the Company to clarify the Company’s easement rights in the State of Mississippi. These agreements have been approved by the Circuit Courts of Harrison County and Jasper County, Mississippi (First Judicial Circuit), and dismissals of the related cases are in progress. These agreements have not had any material impact on the Company’s financial statements.
In addition, in late 2001, certain subsidiaries of Southern Company, including Alabama Power, Georgia Power, Gulf Power, the Company, and Southern Telecom, Inc., (a subsidiary of SouthernLINC Wireless), were named as defendants in a lawsuit brought by a telecommunications company that uses certain of the defendants’ rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. The Company believes that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. An adverse outcome in this matter, combined with an adverse outcome against the telecommunications company in one or more of the right of way lawsuits, could result in substantial judgments; however, the final outcome of these matters cannot now be determined.
Retail Regulatory Matters
Performance Evaluation Plan
The Company’s retail base rates are set under Performance Evaluation Plan (PEP), a rate plan approved by the Mississippi PSC. PEP was designed with the objective that PEP would reduce the impact of rate changes on the customer and provide incentives for the Company to keep customer prices low and customer satisfaction and reliability high. PEP is a mechanism for rate adjustments based on three indicators: price, customer satisfaction, and service reliability.
In May 2004, the Mississippi PSC approved the Company’s request to modify certain portions of its PEP and to reclassify, to jurisdictional cost of service the 266 megawatts of Plant Daniel Units 3 and 4 capacity, effective January 1, 2004. The Mississippi PSC authorized the Company to include the related costs and revenue credits in jurisdictional rate base, cost of service, and revenue requirement calculations for purposes of retail rate recovery. The Company amortized the regulatory liability established pursuant to the Mississippi PSC’s interim December 2003 accounting order, as approved in the May 2004 order, to earnings as follows: $16.5 million in 2004, $25.1 million in 2005, $13.0 million in 2006, and $5.7 million in 2007, resulting in increases to earnings in each of those years.
In addition, in May 2004, the Mississippi PSC also approved the Company’s requested changes to PEP, including the use of a forward-looking test year, with appropriate oversight; annual, rather than semi-annual, filings; and certain changes to the performance indicator mechanisms. Rate changes will be limited to four percent of retail revenues annually under the revised PEP. PEP will remain in effect until the Mississippi PSC modifies, suspends, or terminates the plan.
In April 2007, the Mississippi PSC issued an order allowing the Company to defer approximately $10.4 million of certain reliability related maintenance costs beginning January 1, 2007, and recover them over a four-year period beginning January 1, 2008. These costs related to system upgrades and improvements that were needed as follow-up to emergency repairs that were made subsequent to Hurricane Katrina. At December 31, 2007, the Company had incurred and deferred the retail portion of $9.5 million of such costs, of which $2.4 million is included in current assets as other regulatory assets and $7.1 million is included in long-term other regulatory assets.
In September 2007, the Mississippi PSC staff and the Company entered into a stipulation that included adjustments to expenses which resulted in a one-time credit to retail customers of approximately $1.1 million. In November 2007, the Mississippi PSC issued an order requiring the Company to refund this amount to its retail customers no later than December 2007. This amount was totally refunded as a credit to customer bills by December 31, 2007.
In December 2007, the Company submitted its annual PEP filing for 2008, which resulted in a rate increase of 1.983% or $15.5 million annually, effective January 2008. In December 2006, the Company submitted its annual PEP filing for 2007, which resulted in no rate change.
In December 2007, the Company received an order from the Mississippi PSC requiring it to defer $1.4 million associated with the retail portion of certain tax credits and adjustments related to permanent timing differences pertaining to its 2006 income tax returns
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filed in September 2007. These tax differences have been recorded in a regulatory liability included in the current portion of other regulatory liabilities and will be amortized ratably over a twelve month period beginning January 2008.
System Restoration Rider
In September 2006, the Company filed with the Mississippi PSC a request to implement a System Restoration Rider (SRR), to increase the Company’s cap on the property damage reserve and to authorize the calculation of an annual property damage accrual based on a formula. The purpose of the SRR is to provide for recovery of costs associated with property damage (including certain property insurance and the costs of self insurance) and to facilitate the Mississippi PSC’s review of these costs. The Company would be required to make annual SRR filings to determine the revenue requirement associated with the property damage. The Company recorded a regulatory liability in the amount of approximately $2.4 million in 2006 and $0.6 million in 2007 for the estimated amount due to retail customers that would be passed through SRR. The Company along with the Mississippi Public Utilities Staff has agreed and stipulated to a revised SRR calculation method that would no longer require the Mississippi PSC to set a cap on the property damage reserve or to authorize the calculation of an annual property damage accrual. Under the revised SRR calculation method, the Mississippi PSC would periodically agree on SRR revenue levels that would be developed based on historical data, expected exposure, type and amount of insurance coverage excluding insurance costs, and other relevant information. It is anticipated that the Mississippi PSC would agree on the applicable SRR revenue level every three years, unless a significant change in circumstances occurs such that the Company and the Mississippi Public Utilities Staff or the Mississippi PSC deems that a more frequent change would be just, reasonable and in the public interest. The Company will submit annual filings setting forth SRR-related revenues, expenses and investment for the projected filing period, as well as the true-up for the prior period. The Company is currently waiting on a final order from the Mississippi PSC determining the final disposition of the regulatory liability and determination of the final SRR rate schedule.
Environmental Compliance Overview Plan
The ECO Plan establishes procedures to facilitate the Mississippi PSC’s overview of the Company’s environmental strategy and provides for recovery of costs (including cost of capital) associated with environmental projects approved by the Mississippi PSC. Under the ECO Plan, any increase in the annual revenue requirement is limited to 2% of retail revenues. However, the ECO Plan also provides for carryover of any amount over the 2% limit into the next year’s revenue requirement. The Company conducts studies, when possible, to determine the extent of any required environmental remediation. Should such remediation be determined to be probable, reasonable estimates of costs to clean up such sites are developed and recognized in the financial statements. In accordance with the Mississippi PSC order, the Company recovers such costs under the ECO Plan as they are incurred.
On February 1, 2008, the Company filed with the Mississippi PSC its annual ECO Plan evaluation for 2008 which resulted in an 18 cents per 1,000 KWH decrease in the rate for retail residential customers. Hearings with the Mississippi PSC are expected to be held in April 2008. The outcome of the 2008 filing cannot now be determined. In April 2007, the Mississippi PSC approved the Company’s 2007 ECO Plan, which included an 86 cent per 1,000 KWH increase for retail residential customers. This increase represented an addition of approximately $7.5 million in annual revenues for the Company. The new rates were effective in April 2007.
Fuel Cost Recovery
The Company establishes, annually, a fuel cost recovery factor that is approved by the Mississippi PSC. Over the past several years, the Company has continued to experience higher than expected fuel costs for coal and natural gas. The Company is required to file for an adjustment to the fuel cost recovery factor annually; such filing occurred in November 2007. As a result, the Mississippi PSC approved an increase in the fuel cost recovery factor effective January 2008 in an amount equal to 4.2% of total retail revenues. The Company’s operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, this increase to the billing factor will have no significant effect on the Company’s revenues or net income, but will increase annual cash flow. At December 31, 2007, the amount of under recovered fuel costs included in the balance sheets was $40.5 million compared to $50.8 million at December 31, 2006.
Storm Damage Cost Recovery
In August 2005, Hurricane Katrina hit the Gulf Coast of the United States and caused significant damage within the Company’s service area. The estimated total storm restoration costs relating to Hurricane Katrina through December 31, 2007 of $302.4 million, which was net of expected insurance proceeds of approximately $77 million, without offset for the property damage reserve of
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$3.0 million was affirmed by the Mississippi PSC in June 2006, and the Company was ordered to establish a regulatory asset for the retail portion. The Mississippi PSC issued an order directing the Company to file an application with the MDA for a Community Development Block Grant (CDBG). In October 2006, the Company received from the MDA a CDBG in the amount of $276.4 million, which was allocated to both the retail and wholesale jurisdictions. In the same month, the Mississippi PSC issued a financing order that authorized the issuance of system restoration bonds for the remaining $25.2 million of the retail portion of storm recovery costs not covered by the CDBG. The Company incurred the $302.4 million total storm costs affirmed by the Mississippi PSC as of December 31, 2007, and will report the retail regulatory liability balance of $0.1 million to the Mississippi PSC to determine the final disposition of this balance.
The Company maintains a reserve to cover the cost of damage from major storms to its transmission and distribution facilities and the cost of uninsured damage to its generation facilities and other property. A 1999 Mississippi PSC order allowed the Company to accrue $1.5 million to $4.6 million to the reserve annually, with a maximum reserve totaling $23 million. In October 2006, in conjunction with the Mississippi PSC Hurricane Katrina-related financing order, the Mississippi PSC ordered the Company to cease all accruals to the retail property damage reserve, until a new reserve cap is established. However, in the same financing order, the Mississippi PSC approved the replenishment of the property damage reserve with $60 million to be funded with a portion of the proceeds of bonds to be issued by the Mississippi Development Bank on behalf of the State of Mississippi and reported as liabilities by the State of Mississippi. These funds were received in June 2007.
In June 2006, the Mississippi PSC issued an order certifying actual storm restoration costs relating to Hurricane Katrina through April 30, 2006 of $267.9 million and affirmed estimated additional costs through December 31, 2007, of $34.5 million, for total storm restoration costs of $302.4 million, which was net of expected insurance proceeds of approximately $77 million, without offset for the property damage reserve of $3.0 million. Of the total amount, $292.8 million applies to the Company’s retail jurisdiction. The order directed the Company to file an application with the MDA for a CDBG.
In October 2006, the Company received from the MDA a CDBG in the amount of $276.4 million. The Company has appropriately allocated and applied these CDBG proceeds to both retail and wholesale storm restoration cost recovery. The retail portion of $267.6 million was applied to the retail regulatory asset in the balance sheets. For the remaining wholesale portion of $8.8 million, $3.3 million was credited to operations and maintenance expense in the statements of income and $5.5 million was applied to accumulated provision for depreciation in the balance sheets. In 2006, the CDBG proceeds related to capital of $152.7 million and $120.3 million related to retail operations and maintenance expense were included in the statement of cash flows as separate line items. In 2007, the storm restoration bond proceeds related to $35.0 million capital, of which $10.9 million related to retail restoration and $24.1 million related to the storm operations center, and $14.3 million related to retail operations and maintenance expenses are included in the statements of cash flows as separate line items. The cash portions of storm costs are included in the statements of cash flows under Hurricane Katrina accounts payable, property additions, and cost of removal, net of salvage and totaled approximately $0.1 million, $12.5 million, and $(8.1) million, respectively, for 2007, $50.5 million, $54.2 million, and $4.6 million, respectively, for 2006 and totaled approximately $82.1 million, $81.7 million, and $18.4 million, respectively, for 2005.
In October 2006, the Mississippi PSC issued a financing order that authorized the issuance of $121.2 million of system restoration bonds. This amount includes $25.2 million for the retail storm recovery costs not covered by the CDBG, $60 million for a property damage reserve, and $36 million for the retail portion of the construction of the storm operations facility. The storm restoration bonds were issued by the Mississippi Development Bank on June 1, 2007, on behalf of the State of Mississippi. On June 1, 2007, the Company received a grant payment of $85.2 million from the State of Mississippi representing recovery of $25.2 million in retail storm restoration costs incurred or to be incurred and $60.0 million to increase the Company’s property damage reserve. In the fourth quarter of 2007, the Company received two additional grant payments totaling $24.1 million for expenditures incurred for construction of a new storm operations center. The funds received related to previously incurred storm restoration expenditures have been accounted for as a government grant and have been recorded as a reduction to the regulatory asset that was recorded as the storm restoration expenditures were incurred. The funds received for storm restoration expenditures to be incurred were recorded as a regulatory liability. The Company will receive further grant payments of up to $11.9 million as expenditures are incurred to construct the new storm operations center.
The funds received with respect to certain of the grants were funded through the Mississippi Development Bank’s issuance of tax-exempt bonds. Due to the tax-exempt status to the holders of bonds for federal income tax purposes, the use of the proceeds is limited to expenditures that qualify under the Internal Revenue Code. Prior to the receipt of the proceeds from the tax-exempt bonds in 2007, management of the Company represented to the Mississippi Development Bank that all expenditures to date qualify under the Internal Revenue Code. Should the Company use the proceeds for non-qualifying expenditures, it could be required to return that portion of
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the proceeds received from the tax-exempt bond issuance that was applied to non-qualifying expenditures. Management expects that all future expenditures will also qualify and that no proceeds will be required to be returned.
In order for the State of Mississippi to repay the bonds issued by the Mississippi Development Bank, the State of Mississippi has established a system restoration charge that will be charged to all retail electric utility customers within the Company’s service area. This charge will be collected by the Company through the retail customers’ monthly statement and remitted to the State of Mississippi on a monthly basis. The system restoration charge is the property of the State of Mississippi. The Company’s only obligation is to collect and remit the proceeds of the charge. The Company began collecting the system restoration charge on June 20, 2007, and remitted the first payment to the State of Mississippi on July 17, 2007.
The Company incurred the $302.4 million total storm costs affirmed by the Mississippi PSC as of December 31, 2007. The balance in the retail regulatory liability account at December 31, 2007 was $0.1 million, which is net of the retail portion of insurance proceeds of $78.1 million, CDBG proceeds of $267.6 million, storm restoration bond proceeds of $25.1 million, and tax credits of $0.3 million. Retail costs incurred through December 31, 2007, include approximately $158.5 million of capital and $134.4 million of operations and maintenance expenditures. The Company will report the regulatory liability balance to the Mississippi PSC to determine the final disposition of this balance.
In June 2006, the Mississippi PSC order also granted continuing authority to record a regulatory asset in an amount equal to the retail portion of the recorded Hurricane Katrina restoration costs. For any future event causing damage to property beyond the balance in the reserve, the order also granted the Company the authority to record a regulatory asset. The Company would then apply to the Mississippi PSC for recovery of such amounts or for authority to otherwise dispose of the regulatory asset. The Company continues to report actual storm expenses to the Mississippi PSC periodically.
Construction Projects
In June 2006, the Company filed an application with the U.S. Department of Energy (DOE) for certain tax credits available to projects using clean coal technologies under the Energy Policy Act of 2005. The proposed project is an advanced coal gasification facility located in Kemper County, Mississippi, that would use locally mined lignite coal. The proposed 693 megawatt plant is expected to require an approximate investment of $1.5 billion, excluding the mine cost, and is expected to be completed in 2013. The DOE subsequently certified the project and in November 2006, the Internal Revenue Service (IRS) allocated Internal Revenue Code Section 48A tax credits of $133 million to the Company. The utilization of these credits is dependent upon meeting the certification requirements for the project under the Internal Revenue Code. The plant would use an air-blown integrated gasification combined cycle technology that generates power from low-rank coals and coals with high moisture or high ash content. These coals, which include lignite, make up half the proven U.S. and worldwide coal reserves. The Company is undertaking a feasibility assessment of the project, which could take up to two years. On December 21, 2006, the Mississippi PSC approved the Company’s request for accounting treatment of the costs associated with the Company’s generation resource planning, evaluation, and screening activities. The Mississippi PSC gave the Company the authority to create and recognize a regulatory asset for such costs. On December 28, 2007, the Company received an order allowing it to defer the amortization of these costs to January 2009. In addition, Mississippi received approval for the updated estimate of approximately $23.8 million in total generation screening and evaluation costs ($16 million for the retail portion). At December 31, 2007, the Company had spent $18.1 million in total, of which $2.7 million related to land purchases had been capitalized, the retail portion of $11.2 million had been deferred in other regulatory assets, and the wholesale portion of $4.2 million has been expensed. The retail portion of these costs will be charged to and remain as a regulatory asset until the Mississippi PSC determines the prudence and ultimate recovery of such costs, which decision is expected in January 2009. The balance of such regulatory asset will be included in the Company’s rate base for ratemaking purposes. Approval by various regulatory agencies, including the Mississippi PSC, will also be required if the project proceeds. The final outcome of this matter cannot now be determined.
4. JOINT OWNERSHIP AGREEMENTS
The Company and Alabama Power own, as tenants in common, Units 1 and 2, (total capacity of 500 megawatts) at Greene County Steam Plant, which is located in Alabama and operated by Alabama Power. Additionally, the Company and Gulf Power, own as tenants in common, Units 1 and 2, (total capacity of 1,000 megawatts) at Plant Daniel, which is located in Mississippi and operated by the Company.
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At December 31, 2007, the Company’s percentage ownership and investment in these jointly owned facilities were as follows:
The Company’s proportionate share of plant operating expenses is included in the statements of income.
5. INCOME TAXES
Southern Company files a consolidated federal income tax return and combined income tax returns for the State of Alabama and the State of Mississippi. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if it filed a separate income tax return. In accordance with Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability.
Current and Deferred Income Taxes
Details of the income tax provisions were as follows:
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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:
At December 31, 2007, the tax-related regulatory assets and liabilities were $9.5 million and $16.3 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest. These liabilities are attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized investment tax credits.
In accordance with regulatory requirements, deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $1.1 million, $1.1 million, and $1.2 million for 2007, 2006, and 2005, respectively. At December 31, 2007, all investment tax credits available to reduce federal income taxes payable had been utilized.
Effective Tax Rate
The provision for income taxes differs from the amount of income taxes determined by applying the applicable U.S. federal statutory rate to earnings before income taxes and preferred dividends as a result of the following:
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The American Jobs Creation Act of 2004 created a tax deduction for the portion of income attributable to United States production activities as defined in Internal Revenue Code Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for years 2007 through 2009, and a 9% rate applicable for all years after 2009. The increase from 3% in 2006 to 6% in 2007 was one of several factors that increased the Company’s 2007 deduction by $0.3 million over the 2006 deduction. The resulting additional tax benefit was over $0.1 million.
Unrecognized Tax Benefits
On January 1, 2007, the Company adopted FIN 48, which requires companies to determine whether it is “more likely than not” that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. It also provides guidance on the recognition, measurement, and classification of income tax uncertainties, along with any related interest and penalties.
Prior to the adoption of FIN 48, the Company had unrecognized tax benefits which were previously accrued under Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies” of approximately $0.6 million. The total $0.6 million in unrecognized tax benefits would impact the Company’s effective tax rate if recognized. For 2007, the total amount of unrecognized tax benefits increased by $0.3 million, resulting in a balance of $0.9 million as of December 31, 2007.
Changes during the year in unrecognized tax benefits were as follows:
Impact on the Company’s effective tax rate, if recognized, is as follows:
Accrued interest for unrecognized tax benefits:
The Company classifies interest on tax uncertainties as interest expense. Net interest accrued for the year ended December 31, 2007, was $106 thousand. The Company did not accrue any penalties on uncertain tax positions.
The IRS has audited and closed all tax returns prior to 2004. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2002.
It is reasonably possible that the amount of the unrecognized benefit with respect to certain of the Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The possible settlement of the production activities
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deduction methodology and/or the conclusion or settlement of federal or state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
6. FINANCING
Long-Term Debt Payable to Affiliated Trust
The Company formed a wholly-owned trust subsidiary for the purpose of issuing preferred securities. The proceeds of the related equity investment and preferred security sale were loaned back to the Company through the issuance of junior subordinated notes which constitute substantially all of the assets of the trust and were reflected in the balance sheets as Long-term Debt. The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constituted a full and unconditional guarantee by it of the trust’s payment obligations with respect to these securities. During 2007, the Company redeemed its last remaining series of preferred securities, which totaled $36 million. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for the trust and the related securities.
Pollution Control Bonds
Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control facilities. The Company is required to make payments sufficient for authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2007, was $82.7 million.
Securities Due Within One Year
At December 31, 2007, the Company has scheduled maturities of capital leases due within one year totaling $1.1 million. There were no scheduled maturities or redemptions of securities due within one year at December 31, 2006.
Debt maturities through 2012 applicable to total long-term debt are as follows: $1.1 million in 2008; $41.2 million in 2009; $1.3 million in 2010; $1.4 million in 2011; and $0.6 million in 2012.
Outstanding Classes of Capital Stock
The Company currently has preferred stock, depositary preferred stock (each share of depositary preferred stock representing one-fourth of a share of preferred stock), and common stock authorized and outstanding. The Company’s preferred stock and depositary preferred stock, without preference between classes, rank senior to the Company’s common stock with respect to payment of dividends and voluntary or involuntary dissolution. Certain series of the preferred stock and depositary preferred stock are subject to redemption at the option of the Company on or after a specified date (typically 5 or 10 years after the date of issuance) at a redemption price equal to 100% of the liquidation amount of the stock.
Dividend Restrictions
The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
Bank Credit Arrangements
At the beginning of 2008, the Company had total unused committed credit agreements with banks of $181 million, all of which expire in 2008. The facilities contain $39 million 2-year term loan options and $15 million 1-year term loan options. The Company expects to renew its credit facilities, as needed, prior to expiration.
In connection with these credit arrangements, the Company agrees to pay commitment fees based on the unused portions of the commitments or to maintain compensating balances with the banks. Commitment fees are 1/8 of 1% or less for the Company. Compensating balances are not legally restricted from withdrawal.
This $181 million in unused credit arrangements provides required liquidity support to the Company’s borrowings through a commercial paper program. At December 31, 2007, the Company had $9.9 million outstanding in commercial notes. The credit arrangements also provide support to the Company’s variable daily rate tax-exempt pollution control bonds totaling $40.1 million.
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During 2007, the peak amount outstanding for short-term debt was $133.4 million and the average amount outstanding was $57.4 million. The average annual interest rate on short-term debt was 5.3% for 2007 and 5.19% for 2006.
Financial Instruments
The Company also enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company has implemented fuel-hedging programs with the approval of the Mississippi PSC. The Company enters into hedges of forward electricity sales. There was no material ineffectiveness recorded in earnings in 2007, 2006, or 2005.
At December 31, 2007, the fair value gains/(losses) of energy-related derivative contracts were reflected in the financial statements as follows:
The fair value gains or losses for cash flow hedges are recorded as regulatory assets and liabilities if they are recoverable through the regulatory clauses, otherwise they are recorded in other comprehensive income, and are recognized in earnings at the same time the hedged items affect earnings. For the year 2008, approximately $1.0 million of pre-tax gains are expected to be reclassified from other comprehensive income to revenues. The Company has energy-related hedges in place up to and including 2009.
7. COMMITMENTS
Construction Program
The Company is engaged in continuous construction programs, currently estimated to total $186 million in 2008, of which $8 million is related to Hurricane Katrina restoration, $226 million in 2009, and $211 million in 2010. The construction program is subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include changes in business conditions; acquisition of additional generation assets; revised load growth estimates; changes in environmental regulations; changes in FERC rules and regulations; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2007, significant purchase commitments were outstanding in connection with the construction program. The Company has no generating plants under construction. Capital improvements to generating, transmission, and distribution facilities, including those to meet environmental standards, will continue.
Long-Term Service Agreements
The Company has entered into a Long-Term Service Agreement (LTSA) with General Electric (GE) for the purpose of securing maintenance support for the leased combined cycle units at Plant Daniel. The LTSA provides that GE will cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in the contract.
In general, the LTSA is in effect through two major inspection cycles of the units. Scheduled payments to GE under the LTSA, which are subject to price escalation, are made monthly based on estimated operating hours of the units and are recognized as expense based on actual hours of operation. The Company has recognized $9.7 million, $8.4 million, and $7.9 million for 2007, 2006, and 2005, respectively, which is included in maintenance expense in the statements of income. Remaining payments to GE under this agreement are currently estimated to total $144 million over the next 13 years. However, the LTSA contains various cancellation provisions at the option of the Company.
The Company also has entered into a LTSA with ABB Power Generation Inc. (ABB) for the purpose of securing maintenance support for its Chevron Unit 5 combustion turbine plant. In summary, the LTSA stipulates that ABB will perform all planned maintenance on the covered equipment, which includes the cost of all labor and materials. ABB is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in the contract.
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In general, this LTSA is in effect through two major inspection cycles. Scheduled payments to ABB, which are subject to price escalation, are made at various intervals based on actual operating hours of the unit. Payments to ABB under this agreement are currently estimated to total $21.3 million over the remaining term of the agreement, which is approximately 8 years. However, the LTSA contains various cancellation provisions at the option of the Company. Payments made to ABB under the LTSA prior to the performance of any planned maintenance are recorded as a prepayment in the balance sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed. After this contract expires, the Company expects to replace it with a new contract with similar terms.
Fuel Commitments
To supply a portion of the fuel requirements of the generating plants, the Company has entered into various long-term commitments for the procurement of fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide emission allowances. Natural gas purchase commitments contain fixed volumes with prices based on various indices at the time of delivery. Amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2007.
Total estimated minimum long-term obligations at December 31, 2007, were as follows:
Additional commitments for fuel will be required to supply the Company’s future needs.
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and the other traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. The creditworthiness of Southern Power is currently inferior to the creditworthiness of the traditional operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.
Operating Leases
Railcar Leases
The Company and Gulf Power have jointly entered into operating lease agreements for the use of 745 aluminum railcars. The Company has the option to purchase the railcars at the greater of lease termination value or fair market value, or to renew the leases at the end of the lease term. The Company also has multiple operating lease agreements for the use of an additional 120 aluminum railcars that do not contain a purchase option. All of these leases are for the transport of coal to Plant Daniel.
The Company’s share (50%) of the leases, charged to fuel stock and recovered through the fuel cost recovery clause, was $4.4 million in 2007, $4.6 million in 2006, and $3.0 million in 2005. The Company’s annual railcar lease payments for 2008 through 2012 will average approximately $1.6 million and after 2013, lease payments total in aggregate approximately $2.8 million.
In addition to railcar leases, the Company has other operating leases for fuel handling equipment at Plants Daniel and Watson and operating leases for barges and tow/shift boats for the transport of coal at Plant Watson. The Company’s share (50% at Plant Daniel and 100% at Plant Watson) of the leases for fuel handling was charged to fuel handling expense in the amount of $0.9 million in 2007 and $0.9 million in 2006. The Company’s annual lease payments for 2008 through 2011 will average approximately $0.4 million. The Company charged to fuel stock and recovered through fuel cost recovery the barge transportation leases in the amount of $6.2
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million in 2007 and $4.9 million in 2006 related to barges and tow/shift boats. The Company’s annual lease payments for 2008 through 2009, with regards to these barge transportation leases, will average approximately $4.2 million.
Plant Daniel Combined Cycle Generating Units
In May 2001, the Company began the initial 10-year term of the lease agreement for a 1,064 megawatt natural gas combined cycle generating facility built at Plant Daniel (Facility). The Company entered into this transaction during a period when retail access was under review by the Mississippi PSC. The lease arrangement provided a lower cost alternative to its cost based rate regulated customers than a traditional rate base asset. See Note 3 under “Retail Regulatory Matters - Performance Evaluation Plan” for a description of the Company’s formulary rate plan.
In 2003, the Facility was acquired by Juniper Capital L.P. (Juniper), whose partners are unaffiliated with the Company. Simultaneously, Juniper entered into a restructured lease agreement with the Company. Juniper has also entered into leases with other parties unrelated to the Company. The assets leased by the Company comprise less than 50% of Juniper’s assets. The Company is not required to consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease. The lease agreement is treated as an operating lease for accounting purposes, as well as for both retail and wholesale rate recovery purposes. For income tax purposes, the Company retains tax ownership. The initial lease term ends in 2011 and the lease includes a purchase and renewal option based on the cost of the Facility at the inception of the lease, which was $370 million. The Company is required to amortize approximately 4% of the initial acquisition cost over the initial lease term. Eighteen months prior to the end of the initial lease, the Company may elect to renew for 10 years. If the lease is renewed, the agreement calls for the Company to amortize an additional 17% of the initial completion cost over the renewal period. Upon termination of the lease, at the Company’s option, it may either exercise its purchase option or the Facility can be sold to a third party.
The lease provides for a residual value guarantee, approximately 73% of the acquisition cost, by the Company that is due upon termination of the lease in the event that the Company does not renew the lease or purchase the Facility and that the fair market value is less than the unamortized cost of the Facility. A liability of approximately $7 million and $9 million for the fair market value of this residual value guarantee is included in the balance sheets at December 31, 2007 and 2006, respectively. Lease expenses were $27 million in each of the years 2007, 2006, and 2005.
The Company estimates that its annual amount of future minimum operating lease payments under this arrangement, exclusive of any payment related to the residual value guarantee, as of December 31, 2007, are as follows:
8. STOCK OPTION PLAN
Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. As of December 31, 2007, 268 current and former employees of the Company participated in the stock option plan. The maximum number of shares of Southern Company common stock that may be issued under this plan may not exceed 40 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. For certain stock option awards a change in control will provide accelerated vesting.
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The Company’s activity in the stock option plan for 2007 is summarized below:
The number of stock options vested and expected to vest in the future, as of December 31, 2007, was not significantly different from the number of stock options outstanding at December 31, 2007 as stated above. As of December 31, 2007, the weighted average remaining contractual terms for the options outstanding and options exercisable was 6.1 years and 5.0 years, respectively, and the aggregate intrinsic values for the options outstanding and options exercisable was $12.5 million and $10.7 million, respectively.
As of December 31, 2007, there was $0.4 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 10 months.
The total intrinsic value of options exercised during the years ended December 31, 2007, 2006, and 2005, was $2.2 million, $2.4 million, and $4.3 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $0.9 million, $0.9 million, and $1.7 million, respectively, for the years ended December 31, 2007, 2006, and 2005.
9. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 2007 and 2006 are as follows:
The Company’s business is influenced by seasonal weather conditions.
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SOUTHERN POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
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The management of Southern Power Company (the “Company”) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Under management’s supervision, an evaluation of the design and effectiveness of the Company’s internal control over financial reporting was conducted based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2007.
This Annual Report does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report.
/s/ Ronnie L. Bates
Ronnie L. Bates
President and Chief Executive Officer
/s/ Michael W. Southern
Michael W. Southern
Senior Vice President and Chief Financial Officer
February 25, 2008
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Southern Power Company
We have audited the accompanying consolidated balance sheets of Southern Power Company and Subsidiary Companies (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2007 and 2006, and the related consolidated statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2007. 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 consolidated financial statements (pages II-365 to II-380) present fairly, in all material respects, the financial position of Southern Power Company and Subsidiary Companies at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 25, 2008
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OVERVIEW
Business Activities
Southern Power Company and its wholly-owned subsidiaries (the Company) construct, acquire, own, and manage generation assets and sell electricity at market-based prices in the Super-Southeast wholesale market. The Company continues to execute its regional strategy through a combination of acquiring and constructing new power plants and by entering into power purchase agreements (PPAs) with investor owned utilities, independent power producers, municipalities, and electric cooperatives.
In November 2007, the Company and the Orlando Utilities Commission (OUC) mutually agreed to terminate construction of the gasifier portion of the Integrated Gasification Combined Cycle (IGCC) project in Orlando, Florida. This termination was the result of continuing uncertainty surrounding potential Florida state regulations relating to greenhouse gas emissions. See FUTURE EARNINGS POTENTIAL - “Construction Projects - Integrated Coal Gasification Combined Cycle (IGCC)” herein and Note 4 to the financial statements under “IGCC” for additional information. The Company will continue to construct the combined cycle portion of the project for OUC.
In December 2007, the Company completed construction of Plant Oleander Unit 5, a combustion turbine with a nameplate capacity of 163 megawatts (MW) in Brevard County, Florida. The Company has a PPA covering the entire output of this unit from December 2007 through 2027.
In 2007, the Company continued construction on Plant Franklin Unit 3, a combined cycle unit with an expected capacity of 621 MW near Smiths, Alabama. This unit is expected to be completed in 2008. The Company has a PPA covering the entire output of this unit from 2009 through 2015.
As of December 31, 2007, the Company had units totaling 6,896 MW nameplate capacity in commercial operation. The weighted average duration of the Company’s wholesale contracts exceeds 11.3 years, which reduces remarketing risk. The Company continues to face challenges at the federal regulatory level relative to market power and affiliate transactions. See FUTURE EARNINGS POTENTIAL - “FERC Matters” herein for additional information.
Key Performance Indicators
To evaluate operating results and to ensure the Company’s ability to meet its contractual commitments to customers, the Company focuses on several key performance indicators. These indicators include plant availability, peak season equivalent forced outage rate (EFOR), and net income. Plant availability measures the percentage of time during the year that the Company’s generating units are available to be called upon to generate (the higher the better), whereas the EFOR more narrowly defines the hours during peak demand times when the Company’s generating units are not available due to forced outages (the lower the better). Net income is the primary component of the Company’s contribution to Southern Company’s earnings per share goal. The Company’s actual performance in 2007 met or surpassed targets in these key performance areas. See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance.
Earnings
The Company’s 2007 earnings were $131.6 million, a $7.2 million increase over 2006. This increase was primarily the result of increased energy sales due to more favorable weather in 2007. Also contributing to the increase were additional sales from the acquisition of Plant Rowan in September 2006. These increases were partially offset by the $10.7 million after tax loss as a result of the termination of the construction of the gasifier portion of the IGCC project.
The Company’s 2006 earnings were $124.4 million, a $9.7 million increase over 2005. This increase was primarily the result of new PPAs started or acquired in the period, including contracts with Piedmont Municipal Power Authority (PMPA) and EnergyUnited Electric Membership Corporation (EnergyUnited) and the PPAs related to the acquisition of Plants DeSoto and Rowan in June 2006 and September 2006, respectively. Short-term energy sales and increased sales from existing resources also contributed to this increase.
The Company’s 2005 earnings were $114.8 million, a $3.3 million increase over 2004. The 2005 increase was primarily attributed to the acquisition of Plant Oleander in June 2005 and additional revenues associated with energy margins from fully contracted units, which were partially offset by the expiration of PPAs at Plant Dahlberg. In addition, interest expense increased in connection with the
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Plant Oleander acquisition as well as the reduction in capitalized interest due to completion of the Company’s initial construction program.
RESULTS OF OPERATIONS
A condensed income statement follows:
Operating Revenues
Operating revenues in 2007 were $972 million, a $195 million (25.1%) increase from 2006. This increase was primarily due to increased short-term energy sales, a full year of operations at Plant Rowan acquired in September 2006, new sales with EnergyUnited, increased demand under existing PPAs with affiliates as a result of favorable weather within the Southern Company service territory, and higher fuel revenues due to an increase in natural gas prices in 2007. The increase in fuel revenues is accompanied by an increase in related fuel costs and does not have a significant impact on net income.
Operating revenues in 2006 were $777 million, a $4.0 million (0.5%) decrease from 2005. This decrease was primarily due to reduced energy revenues as a result of lower natural gas prices. This reduction is accompanied by a reduction in related fuel costs and does not have a significant net income impact. Offsetting this energy related reduction were increased sales from a full year of operations at Plant Oleander and new sales under PPAs with PMPA and EnergyUnited and those PPAs acquired in the DeSoto and Rowan acquisitions. See FUTURE EARNINGS POTENTIAL - “Power Sales Agreements” herein and Note 2 to the financial statements under “DeSoto and Rowan Acquisitions” for additional information.
Operating revenues in 2005 were $781.0 million, a $79.7 million (11.4%) increase from 2004. This increase was primarily due to PPAs related to the Plant Oleander acquisition, a new PPA with Flint Electric Membership Corporation (Flint EMC), and a full year of revenue from PPAs with Georgia Power at Plant Franklin Unit 2 and Plant Harris Unit 2. The Georgia Power PPA for Plant Franklin Unit 2 had a scheduled sales increase in June 2004, while the PPA for Plant Harris Unit 2 became effective in June 2004. These increases were partially offset by the expiration of PPAs at Plant Dahlberg.
Capacity revenues are an integral component of the Company’s PPAs with both affiliate and non-affiliate customers and represent the greatest contribution to net income. Energy under PPAs is generally sold at variable cost or is indexed to published gas indices. Energy revenues also include fees for support services, fuel storage, and unit start charges. Details of these PPA capacity and energy revenues are as follows:
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Wholesale revenues that were not covered by PPAs totaled $131 million in 2007, which included $40 million of revenues from affiliated companies. Wholesale sales were made in accordance with the Intercompany Interchange Contract (IIC), as approved by the Federal Energy Regulatory Commission (FERC). These non-PPA wholesale revenues will vary from year to year depending on demand and the availability and cost of generating resources at each company that participates in the centralized operation and dispatch of the Southern Company fleet of generating plants (Southern Pool).
Fuel and Purchased Power Expenses
Fuel costs constitute the single largest expense for the Company. Additionally, the Company purchases a portion of its electricity needs from the wholesale market.
In 2007, fuel expense increased by $93.4 million (64.3%) compared to 2006. The increase was driven by a 43.7% increase in generation at Plants Wansley and Dahlberg and a 5.2% increase in the average cost of natural gas.
In 2006, fuel expense decreased by $63.8 million (30.5%) compared to 2005. The decrease was driven by a 25.4% reduction in the average cost of natural gas. Gas prices in 2006 were lower and had less weather-driven volatility than the previous year. The fuel price decrease was partially offset by volume increases primarily from increased generation at Plants Wansley and Dahlberg.
In 2005, fuel expense increased by $81.9 million (64.4%). The increase was driven by a 54.2% increase in the average cost of natural gas.
While there has been a significant upward trend in the cost of natural gas since 2003, prices moderated somewhat in 2006 and 2007. While demand for natural gas in the United States continued to increase in 2007, natural gas supplies have also risen due to increased production and higher storage levels. The Company’s PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel.
Purchased power expense increased $29.3 million (17.1%) in 2007 when compared to 2006, primarily due to increased purchases of lower cost energy resources from the Southern Pool and non-affiliates and contracts with Georgia Electric Membership Corporation and Dalton Utilities. Purchased power volume in 2007 increased 21.0% compared to 2006. Purchased power expense increased $10.7 million (6.6%) in 2006 when compared to 2005, due to purchases from the Southern Pool and contracts with Piedmont Municipal Power Agency (PMPA) and Dalton Utilities. Purchased power expense decreased $28.4 million (15.1%) in 2005 when compared to 2004, due to limited market energy sales as the Company’s generating resources were employed for increased PPA commitments. In 2004, the capacity from the uncontracted units was sold into short-term markets and the related energy sales were often served with lower cost, short-term power purchases from affiliates and non-affiliates.
Purchased power expenses will vary depending on demand and the availability and cost of generating resources available throughout
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the Southern Company system and other contract resources. Load requirements are submitted to the Southern Pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by the Company, affiliate-owned generation, or external purchases.
Other Operations and Maintenance Expenses
In 2007, other operations and maintenance expenses increased $39.7 million (41.7%) compared to 2006. This increase was due primarily to a full year of operations at Plant DeSoto and Plant Rowan acquired in June 2006 and September 2006, respectively, and additional administrative and general expenses as a result of costs incurred to implement the FERC compliance plan. See FUTURE EARNINGS POTENTIAL - “FERC Matters - Intercompany Interchange Contract” herein, Note 2 to the financial statements under “DeSoto and Rowan Acquisitions,” and Note 3 to the financial statements under “FERC Matters - Intercompany Interchange Contract” for additional information.
In 2006 and 2005, other operations and maintenance expenses increased $14.5 million (17.9%) and $5.6 million (7.5%), respectively. These increases were primarily the result of the operation of new generating units from acquisitions of Plant Oleander in June 2005, Plant DeSoto in June 2006, and Plant Rowan in September 2006. See Note 2 to the financial statements under “DeSoto and Rowan Acquisitions” and “Oleander Acquisition” for additional information.
Loss on IGCC Project
In November 2007, the Company and OUC mutually agreed to terminate the construction of the gasifier portion of the IGCC project. The Company will continue construction of the gas-fired combined cycle generating facility, owned by OUC. The Company recorded a loss in the fourth quarter 2007 of approximately $17.6 million related to the cancellation of the gasifier portion of the IGCC project. This loss consists of the write-off of construction costs of $14.0 million and an accrual for termination payments of $3.6 million. See FUTURE EARNINGS POTENTIAL - “Construction Projects - Integrated Coal Gasification Combined Cycle (IGCC)” herein and Note 4 to the financial statements under “IGCC” for additional information.
Depreciation and Amortization
Depreciation and amortization increased $8.0 million (12.2%), $11.7 million (21.6%), and $3.1 million (6%) in 2007, 2006, and 2005, respectively. These increases were primarily the result of additional depreciation related to Plants DeSoto and Rowan acquired in June 2006 and September 2006, respectively, Plant Oleander acquired in June 2005, and higher depreciation rates from a depreciation study adopted in March 2006. See Note 1 to the financial statements under “Depreciation” and Note 2 to the financial statements under “DeSoto and Rowan Acquisitions” and “Oleander Acquisition” for additional information. See FUTURE EARNINGS POTENTIAL - “Other Matters” herein for additional information regarding a new depreciation study.
Taxes Other than Income Taxes
The 2007 increase in taxes other than income taxes was not material.
Taxes other than income taxes increased $2.3 million (17.4%) and $2.0 million (18.1%) in 2006 and 2005, respectively. This was primarily due to incremental ad valorem taxes on new assets: Plants DeSoto and Rowan acquired in June 2006 and September 2006, respectively, and Plant Oleander acquired in June 2005. See Note 2 to the financial statements under “DeSoto and Rowan Acquisitions” and “Oleander Acquisition” for additional information.
Interest Expense, Net of Amounts Capitalized
Interest expense decreased $1.0 million (1.2%) in 2007 primarily due to additional capitalized interest of $10.9 million on active construction projects and reduced interest on commercial paper of $2.0 million due to lower borrowing levels. This decrease was partially offset by $11.9 million increase in interest on $200 million of senior notes that were issued in November 2006.
Interest expense increased $0.8 million (1.0%) and $13.3 million (20.0%) in 2006 and 2005, respectively. The 2006 increase was primarily the result of additional debt incurred for acquisitions. This increase was offset by $5.6 million of interest capitalized on active construction projects. The 2005 increase was due to incremental debt incurred for the Oleander acquisition. Additional factors for the 2005 increase included a reduction of $17.4 million in interest costs being capitalized as projects reached completion, were sold, or were suspended during those periods. Plant McIntosh Units 10 and 11 were transferred to Georgia Power and construction
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was suspended on Plant Franklin Unit 3 during 2004, effectively ceasing all capitalized interest in 2005. For additional information, see FUTURE EARNINGS POTENTIAL - “Construction Projects,” Note 4 to the financial statements under “IGCC,” and Note 7 to the financial statements under “Construction Programs.”
Other Income (Expense), Net
Changes in other income, net in 2007, 2006, and 2005 were primarily the result of unrealized gains and losses on derivative energy contracts. See FINANCIAL CONDITION AND LIQUIDITY - “Market Price Risk” herein and Notes 1 and 6 to the financial statements under “Financial Instruments.”
Income Taxes
Income taxes increased $1.7 million (2.1%) in 2007, increased $9.9 million (13.9%) in 2006, and decreased $1.1 million (1.5%) in 2005. Fluctuations in income taxes were primarily the result of changes to pre-tax income.
Effects of Inflation
When inflation exceeds projections used in market, term, and cost evaluations performed at contract initiation, the effects of inflation can create an economic loss. In addition, the income tax laws are based on historical costs. Therefore inflation creates an economic loss as the Company is recovering its costs of investments in dollars that could have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company due to large investment in utility plant with long economic lives. Conventional accounting for historical costs does not recognize this economic loss or the partially offsetting gain that arises through financing facilities with fixed money obligations such as long-term debt.
FUTURE EARNINGS POTENTIAL
General
The results of operations for the past three years are not necessarily indicative of future earnings potential. A number of factors affect the opportunities, challenges, and risks of the Company’s competitive wholesale energy business. These factors include the ability to achieve sales growth while containing costs. Another major factor is federal regulatory policy, which may impact the Company’s level of participation in this market. The level of future earnings depends on numerous factors including regulatory matters (such as those related to affiliate contracts), sales, creditworthiness of customers, total generating capacity available in the Southeast, and the successful remarketing of capacity as current contracts expire.
Power Sales Agreements
The Company’s sales are primarily through long-term PPAs. The Company is working to maintain and expand its share of the wholesale market in the Super-Southeast power markets. Recent oversupply of generating capacity in the market is being reduced and the Company expects that many areas of the market will need capacity beyond 2011.
The Company’s PPAs consist of two types of agreements. The first type, referred to as a unit or block sale, is a customer purchase from a dedicated plant unit where all or a portion of the generation from that unit is reserved for that customer. The second type, referred to as requirements service, provides that the Company serve the customer’s capacity and energy requirements from a combination of the customer’s own generating units and from Company resources not dedicated to serve unit or block sales. The Company has rights to purchase power from these customers when economically viable.
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The Company has entered into the following PPAs over the past 3 years:
(a)
Subject to obtaining transmission service.
(b)
Assumed contract through the Plant Rowan acquisition.
(c)
Reflects average annual capacity purchases.
(d)
Contract was assumed from Progress Ventures, Inc. in 2007.
(e)
Assumed contract through the Plant Oleander acquisition.
The Company has PPAs with some of Southern Company’s traditional operating companies and with other investor owned utilities, independent power producers, municipalities, and electric cooperatives. Although some of the Company’s PPAs are with the traditional operating companies, the Company’s generating facilities are not in the traditional operating companies’ regulated rate bases, and the Company is not able to seek recovery from the traditional operating companies’ ratepayers for construction, repair, environmental, or maintenance costs. The Company expects that the capacity payments in the PPAs will produce sufficient cash flow to cover costs, pay debt service, and provide an equity return. However, the Company’s overall profit will depend on numerous factors, including efficient operation of its generating facilities.
As a general matter, existing PPAs provide that the purchasers are responsible for substantially all of the cost of fuel relating to the energy delivered under such PPAs. To the extent a particular generating facility does not meet the operational requirements contemplated in the PPAs, the Company may be responsible for excess fuel costs. With respect to fuel transportation risk, most of the Company’s PPAs provide that the counterparties are responsible for procuring and transporting the fuel to the particular generating facility.
Fixed and variable operation and maintenance costs will be recovered through capacity charges based on dollars-per-kilowatt year or energy charges based on dollars-per-MW hour. In general, the Company has long-term service contracts with General Electric (GE) to reduce its exposure to certain operation and maintenance costs relating to GE equipment. See Note 7 to the financial statements under “Long-Term Service Agreements” for additional information.
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Many of the Company’s PPAs have provisions that require the posting of collateral or an acceptable substitute guarantee in the event that Standard & Poor’s or Moody’s downgrades the credit ratings of the counterparty to an unacceptable credit rating or the counterparty is not rated or fails to maintain a minimum coverage ratio. The PPAs are expected to provide the Company with a stable source of revenue during their respective terms.
The Company has entered into long-term power sales agreements for an average of 91% of its available capacity for the next 10 years as follows:
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.
In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales by the Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level.
In late June and July 2007, hearings were held in this proceeding and the presiding administrative law judge issued an initial decision on November 9, 2007 regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the Company to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates, and could also result in refunds of up to $0.7 million, plus interest. The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter.
On June 21, 2007, the FERC issued its final rule regarding market-based rate authority. The FERC generally retained its current market-based rate standards. The impact of this order and its effect on the generation dominance proceeding cannot now be determined.
Intercompany Interchange Contract
The majority of the Company’s generation fleet is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies, the Company, and Southern Company Services, Inc., as agent, under the terms of which the Southern Pool is operated, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining the Company as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of the Company, the FERC authorized the Company’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct.
In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms and Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on
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behalf of the Company. Southern Company filed with the FERC in November 2006 a compliance plan in connection with the order. On April 19, 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. On November 19, 2007, Southern Company notified the FERC that the plan had been implemented and the FERC division of audits subsequently began an audit pertaining to compliance implementation and related matters, which is ongoing. The Company’s cost of implementing the plan, including the modifications, is expected to be approximately $8 million annually.
Income Tax Matters
Internal Revenue Code Section 199 Domestic Production Deduction
The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in the Internal Revenue Code of 1986, as amended, Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for years 2007 through 2009, and a 9% rate applicable for all years after 2009. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.
Bonus Depreciation
On February 13, 2008, President Bush signed the Economic Stimulus Act of 2008 (Stimulus Act) into law. The Stimulus Act includes a provision that allows 50% bonus depreciation for certain property acquired in 2008 and placed in service in 2008 or, in certain limited cases, 2009. The Company is currently assessing the financial implications of the Stimulus Act; however, the ultimate impact cannot be determined at this time.
Environmental Matters
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 possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company.
New environmental legislation or regulations, such as requirements related to greenhouse gases, or changes to existing statutes or regulations, could affect many areas of the Company’s operations. While the Company’s PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such regulatory or legislative changes cannot be determined at this time.
Because the Company’s units are newer gas-fired generating facilities, costs associated with environmental compliance for these facilities have been less significant than for similarly situated coal-fired generating facilities or older gas-fired generating facilities. Environmental, natural resource, and land use concerns, including the applicability of air quality limitations, the availability of water withdrawal rights, uncertainties regarding aesthetic impacts such as increased light or noise, and concerns about potential adverse health impacts, can, however, increase the cost of siting and operating any type of future electric generating facility. The impact of such statutes and regulations on the Company cannot be determined at this time.
Litigation over environmental issues and claims of various types, including property damage, common law nuisance, and citizen enforcement of environmental requirements such as air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such potential litigation against the Company cannot be determined at this time.
Global Climate Issues
Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions continue to be considered in Congress. The ultimate outcome of these proposals cannot be determined at this time; however, mandatory restrictions on the Company’s greenhouse gas emissions could result in significant additional compliance costs that could affect results of operations, cash flows, and financial condition if such costs are not recovered under applicable power purchase agreements.
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In April 2007, the U.S. Supreme Court ruled that the Environmental Protection Agency (EPA) has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. The EPA is currently developing its response to this decision. Regulatory decisions that will follow from this response may have implications for both new and existing stationary sources, such as power plants. The ultimate outcome of these rulemaking activities cannot be determined at this time; however, as with the current legislative proposals, mandatory restrictions on the Company’s greenhouse gas emissions could result in significant additional compliance costs that could affect results of operations, cash flows, and financial condition if such costs are not recovered under applicable PPAs.
In addition, some states are considering or have undertaken actions to regulate and reduce greenhouse gas emissions. For example, on July 13, 2007, the Governor of the State of Florida signed three executive orders addressing reduction of greenhouse gas emissions within the state, including statewide emission reduction targets beginning in 2017. Included in the orders is a directive to the Florida Secretary of Environmental Protection to develop rules adopting maximum allowable emissions levels of greenhouse gases for electric utilities, consistent with the statewide emission reduction targets, and a request to the Florida Public Service Commission to initiate rulemaking requiring utilities to produce at least 20% of their electricity from renewable sources. The impact of these orders on the Company will depend on the development, adoption, and implementation of any rules governing greenhouse gas emissions, and the ultimate outcome cannot be determined at this time.
International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. Current efforts focus on a potential successor to the Kyoto Protocol for the post 2008 through 2012 timeframe. The Company continues to evaluate its future energy and emission profiles and is participating in voluntary programs to reduce greenhouse gas emissions and to help develop and advance technology to reduce emissions.
Construction Projects
Plant Franklin Unit 3
The Company restarted construction activities on Plant Franklin Unit 3 in 2006, with an expected completion date in June 2008. The total cost is expected to be approximately $318.6 million, of which $280.4 million had been spent as of December 31, 2007. The expected capacity of this unit is 621 MW and will be used to provide annual capacity for a PPA with Constellation Energy Group, Inc. from 2009 through 2015.
Plant Oleander Unit 5
The Company completed construction of Plant Oleander Unit 5 in December 2007. Costs incurred through December 31, 2007 were $56.9 million. This unit is a combustion turbine with a nameplate capacity of 163 MW in Brevard County, Florida. This unit is contracted to provide annual capacity for a PPA with the Florida Municipal Power Agency from 2007 through 2027.
Integrated Coal Gasification Combined Cycle (IGCC)
In December 2005, the Company and the OUC executed definitive agreements for development of a 285-MW IGCC project in Orlando, Florida. The definitive agreements provided that the Company would own at least 65% of the gasifier portion of the IGCC project. OUC would own the remainder of the gasifier portion and 100% of the combined cycle portion of the IGCC project. The Company signed cooperative agreements with the U.S. Department of Energy (DOE) that provided up to $293.75 million in grant funding for the gasification portion of this project. The IGCC project was expected to begin commercial operation in 2010. Due to continuing uncertainty surrounding potential state regulations relating to greenhouse gas emissions, the Company and OUC mutually agreed to terminate the construction of the gasifier portion of the IGCC project in November 2007. The Company will continue construction of the gas-fired combined cycle generating facility for OUC under a fixed-price, long-term contract for engineering, procurement and construction services. The Company recorded a loss in the fourth quarter 2007 of approximately $17.6 million related to cancellation of the gasifier portion of the IGCC project. This amount is net of reimbursements from OUC and the DOE. This loss consists of the write-off of construction costs of $14.0 million and an accrual for termination costs of $3.6 million. All termination costs are expected to be paid in 2008. As part of the termination agreement with OUC, the Company agreed to sell a tract of land in Orange County, Florida to OUC. The Company will record a gain of approximately $6 million on this sale in the first quarter of 2008.
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Other Matters
The Company completed a depreciation study in 2006 and updated the composite depreciation rates for its property, plant, and equipment. This change in estimate arises from changes in useful life assumptions for certain components of plant in service. This change increased depreciation expense and reduced net income. The 2006 net income impact of this change was $3.8 million. See Note 1 to the financial statements under “Depreciation” for additional information. The Company is currently undergoing a new depreciation study that will be implemented in 2008. It is expected that the results of this new study will increase depreciation expense and reduce net income. The net income impact of this change is estimated to be $2.7 million annually.
From time to time, 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. 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 and water quality standards, has increased generally throughout the United States. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any arising from such current proceedings would have a material adverse effect on the Company’s financial statements. See Note 3 to the financial statements for information regarding material issues.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the critical accounting policies and estimates described below with the Audit Committee of Southern Company’s Board of Directors.
Revenue Recognition
The Company’s revenue recognition depends on appropriate classification and documentation of transactions in accordance with Financial Accounting Standards Board (FASB) Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted (SFAS No. 133). In general, the Company’s power sale transactions can be classified in one of four categories: non-derivatives, normal sales, cash flow hedges, and mark to market. For more information on derivative transactions, see FINANCIAL CONDITION AND LIQUIDITY - “Market Price Risk” and Notes 1 and 6 to the financial statements under “Financial Instruments.” The Company’s revenues are dependent upon significant judgments used to determine the appropriate transaction classification, which must be documented upon the inception of each contract. Factors that must be considered in making these determinations include:
•
Assessing whether a sales contract meets the definition of a lease;
•
Assessing whether a sales contract meets the definition of a derivative;
•
Assessing whether a sales contract meets the definition of a capacity contract;
•
Assessing the probability at inception and throughout the term of the individual contract that the contract will result in physical delivery;
•
Ensuring that the contract quantities do not exceed available generating capacity (including purchased capacity);
•
Identifying the hedging instrument, the hedged transaction, and the nature of the risk being hedged; and
•
Assessing hedge effectiveness at inception and throughout the contract term.
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Southern Power Company and Subsidiary Companies 2007 Annual Report
Normal Sale and Non-Derivative Transactions
The Company has capacity contracts that provide for the sale of electricity and that involve physical delivery in quantities within the Company’s available generating capacity. These contracts either do not meet the definition of a derivative or are designated as normal sales thus exempting them from fair value accounting under SFAS No. 133. As a result, such transactions are accounted for as executory contracts; additionally the related revenue is recognized in accordance with Emerging Issues Task Force (EITF) No. 91-6, “Revenue Recognition of Long-Term Power Sales Contracts” on an accrual basis in amounts equal to the lesser of the levelized amount or the amount billable under the contract, over the respective contract periods. Revenues are recorded on a gross basis in accordance with EITF No. 99-19 “Reporting Revenue Gross as a Principal versus Net as an Agent.” Revenues from transactions that do not meet the definition of a derivative are also recorded in this manner. Contracts recorded on the accrual basis represented the majority of the Company’s operating revenues for the year ended December 31, 2007.
Cash Flow Hedge Transactions
The Company designates other derivative contracts for the sale of electricity as cash flow hedges of anticipated sale transactions. These contracts are marked to market through other comprehensive income over the life of the contract. Realized gains and losses are then recognized in revenues as incurred.
Mark-to-Market Transactions
Contracts for sales of electricity that are not normal sales and are not designated as cash flow hedges are marked to market and recorded directly through net income. Net unrealized gains on such contracts were not material for the year ended December 31, 2007.
Percentage of Completion
The Company is currently engaged in a long-term contract for engineering, procurement, and construction services to build a combined cycle unit for OUC. Construction activities commenced in 2006 and are expected to be complete by the end of 2010. Revenues and costs are recognized using the percentage-of-completion method. The Company utilizes the cost-to-cost approach as this method is less subjective than relying on assessments of physical progress. The percentage of completion represents the percentage of the total costs incurred to the estimated total cost of the contract. Revenues and costs are recognized by applying this percentage to the total revenues and estimated costs of the contract.
Asset Impairments
The Company’s investments in long-lived assets are primarily generation assets, whether in service or under construction. The Company evaluates the carrying value of these assets under FASB Statement No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets,” whenever indicators of potential impairment exist. Examples of impairment indicators could include significant changes in construction schedules, current period losses combined with a history of losses, or a projection of continuing losses or a significant decrease in market prices. If an indicator exists, the asset is tested for recoverability by comparing the asset carrying value to the sum of the undiscounted expected future cash flows directly attributable to the asset. A high degree of judgment is required in developing estimates related to these evaluations, which are based on projections of various factors, including the following:
•
Future demand for electricity based on projections of economic growth and estimates of available generating capacity;
•
Future power and natural gas prices, which have been quite volatile in recent years; and
•
Future operating costs.
Acquisition Accounting
The Company has been engaged in a strategy of acquiring assets. The Company has accounted for these acquisitions under the purchase method in accordance with FASB Statement No. 141, “Business Combinations.” Accordingly, the Company has included these operations in the consolidated financial statements from the respective date of acquisition. The purchase price of each acquisition was allocated to the identifiable assets and liabilities based on a valuation prepared by a third party.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2007 Annual Report
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a loss is considered probable and reasonably estimable in accordance with generally accepted accounting principles. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company’s financial statements. These events or conditions include the following:
• Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances, hazardous and solid wastes, and other environmental matters.
• Changes in existing income tax regulations or changes in Internal Revenue Service (IRS) or state revenue department interpretations of existing regulations.
• Identification of additional sites that require environmental remediation or the filing of other complaints in which the Company may be asserted to be a potentially responsible party.
• Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant.
• Resolution or progression of existing matters through the legislative process, the court systems, the IRS, the FERC, or the EPA.
New Accounting Standards
Income Taxes
On January 1, 2007, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), which requires companies to determine whether it is “more likely than not” that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. It also provides guidance on the recognition, measurement, and classification of income tax uncertainties, along with any related interest and penalties. The provisions of FIN 48 were applied to all tax positions beginning January 1, 2007. The adoption of FIN 48 did not have a material impact on the Company’s financial statements.
Fair Value Measurement
The FASB issued FASB Statement No. 157, “Fair Value Measurements” (SFAS No. 157) in September 2006. SFAS No. 157 provides guidance on how to measure fair value where it is permitted or required under other accounting pronouncements. SFAS No. 157 also requires additional disclosures about fair value measurements. The Company adopted SFAS No. 157 in its entirety on January 1, 2008, with no material effect on its financial condition or results of operations.
Fair Value Option
In February 2007, the FASB issued FASB Statement No. 159, “Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115” (SFAS No. 159). This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. The Company adopted SFAS No. 159 on January 1, 2008, with no material effect on its financial condition or results of operations.
Business Combinations
In December 2007, the FASB issued FASB Statement No. 141 (revised 2007), “Business Combinations” (SFAS No. 141R). SFAS No. 141R, when adopted, will significantly change the accounting for business combinations, specifically the accounting for contingent consideration, contingencies, acquisition costs, and restructuring costs. The Company plans to adopt SFAS No. 141R on January 1, 2009. It is likely that the adoption of SFAS No. 141R will have a significant impact on the accounting for any business combinations completed by the Company after January 1, 2009.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2007 Annual Report
In December 2007, the FASB issued FASB Statement No. 160, “Non-controlling Interests in Consolidated Financial Statements” (SFAS No. 160). SFAS No. 160 amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to establish accounting and reporting standards for the non-controlling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary should be reported as equity in the consolidated financial statements and establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation. The Company plans to adopt SFAS No. 160 on January 1, 2009 and is currently assessing its impact, if any.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Net cash provided from operating activities totaled $315.4 million in 2007 increasing 30% from 2006. This increase is primarily due to the increase in sales due to favorable weather and cash received under billings for the engineering, procurement, and construction services to build a combined cycle unit for OUC. The OUC contract is not expected to have any positive or negative cash impacts to the Company over the term of the contract as the Company is not anticipating a profit or loss from this transaction at this time. Net cash used for investing activities totaled $183.9 million in 2007 decreasing 61% from 2006. This decrease was primarily due to the acquisition of Plants DeSoto and Rowan in June 2006 and September 2006, respectively. Gross property additions to utility plant of $183.7 million in 2007 were primarily related to the on-going construction activity at Plant Franklin Unit 3 and the completion of construction at Plant Oleander Unit 5. Net cash used for financing activities was $161.5 million in 2007 compared to $233.4 million provided to the Company in 2006. This change was primarily due to the cash proceeds of $200 million from the issuance of 30-year senior notes in 2006 and borrowings and equity contributions to finance the acquisitions of Plants DeSoto and Rowan.
Other significant balance sheet changes consist of an increase in assets and liabilities for risk management activities of $14.1 million and $12.5 million, respectively. These increases, which do not affect cash, are primarily due to mark-to-market changes on forward energy sales of uncovered plant assets and related gas hedges on the forward sales.
In 2007, the Company also paid $89.8 million in dividends to Southern Company and reduced short-term indebtedness outstanding by $74 million.
Sources of Capital
The Company may use operating cash flows, external funds, or equity capital from Southern Company to finance any new projects, acquisitions, and ongoing capital requirements. The Company expects to generate external funds from the issuance of unsecured senior debt and commercial paper or utilization of credit arrangements from banks. However, the amount, type, and timing of any financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors.
The Company’s current liabilities frequently exceed current assets due to the use of short-term indebtedness as a funding source, as well as cash needs which can fluctuate significantly due to the seasonality of the business. To meet liquidity and capital resource requirements, the Company had at December 31, 2007, $400 million of committed credit arrangements with banks that expire in 2012. Borrowings of $13 million under this facility were outstanding as of December 31, 2007. Proceeds from these credit arrangements may be used for working capital and general corporate purposes as well as liquidity support for the Company’s commercial paper program. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.
The Company’s commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes. At December 31, 2007, there was $36.7 million of commercial paper outstanding. See Note 6 to the financial statements under “Commercial Paper” for additional information.
Management believes that the need for working capital can be adequately met by utilizing commercial paper programs and lines of credit without maintaining large cash balances.
Financing Activities
During 2007, the Company did not issue any new long-term securities.
During 2006, the Company issued $200 million of 30-year unsecured long-term senior notes. The proceeds of the issuance were used to repay a portion of the Company’s outstanding short-term indebtedness and for other general corporate purposes, including the
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2007 Annual Report
Company’s continuous construction program. In conjunction with issuing the securities, the Company terminated $200 million in interest swaps at a cost of $8.1 million. This cost was recorded in other comprehensive income and is being amortized to interest expense over a 10-year period.
The issuance of all securities by the Company is generally subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the FERC, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.
Credit Rating Risk
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and Baa2 or to BBB- or Baa3 or below. These contracts are primarily for physical electricity purchases and sales. At December 31, 2007, the maximum potential collateral requirements at a BBB and Baa2 rating were approximately $9 million and at a BBB- or Baa3 rating were approximately $270 million. At December 31, 2007 the maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $457 million. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash.
In addition, through the acquisition of Plant Rowan, the Company assumed a PPA with Duke Energy that could require collateral, but not accelerated payment, in the event of a downgrade to the Company’s credit rating to below BBB- or Baa3. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade, limited to the Company’s remaining obligations under the contract.
The Company, along with the other members of the Southern Pool, is also party to certain agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade for Alabama Power and/or Georgia Power. These agreements are primarily for natural gas and power price risk management activities. At December 31, 2007, the Company’s total exposure to these types of agreements was approximately $15 million.
Market Price Risk
The Company is exposed to market risks, including changes in interest rates, certain energy-related commodity prices, and, occasionally, currency exchange rates. To manage the volatility attributable to these exposures, the Company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and hedging practices. Company policy is that derivatives are to be used primarily for hedging purposes. Derivative positions are monitored using techniques that include market valuation and sensitivity analysis.
Because energy from the Company’s facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, the Company’s exposure to market volatility in commodity fuel prices and prices of electricity is limited.
The fair value of changes in derivative energy contracts and year-end valuations were as follows at December 31:
(a)
Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2007 Annual Report
At December 31, 2007, the sources of the valuation prices were as follows:
Unrealized pre-tax gains and losses on electric contracts used to hedge anticipated sales, and gas contracts used to hedge anticipated purchases and sales, are deferred in other comprehensive income. Gains and losses on contracts that do not represent hedges are recognized in the statements of income as incurred.
At December 31, 2007, the fair value gains/(losses) of energy related derivative contracts were reflected in the financial statements as follows:
Unrealized pre-tax gains and losses from energy-related derivative contracts recognized in income were not material for any year presented. The Company is exposed to market-price risk in the event of nonperformance by counterparties to the derivative energy contracts. The Company’s policy is to enter into agreements with counterparties that have investment grade credit ratings by Standard & Poor’s and Moody’s or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”
At December 31, 2007, the Company had no variable long-term debt outstanding. Therefore, there would be no effect on annualized interest expense related to long-term debt if the Company sustained a 100 basis point change in interest rates. The Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term.
Capital Requirements and Contractual Obligations
The capital program of the Company is currently estimated to be $109.1 million for 2008, $281.9 million for 2009, and $765.4 million for 2010. These amounts include estimates for potential plant acquisitions and/or new construction as well as ongoing capital improvements. Actual construction costs may vary from these estimates because of changes in factors such as: business conditions; environmental statutes and regulations; FERC rules and regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. Currently, there is one unit at Plant Franklin under construction.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, and other purchase commitments are as follows. See Notes 1, 6, and 7 to the financial statements for additional information.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2007 Annual Report
Contractual Obligations
(a)
All amounts are reflected based on final maturity dates. The Company plans to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
(b)
For additional information, see Notes 1 and 6 to the financial statements.
(c)
The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for the last three years were $135.0 million, $95.3 million, and $80.8 million, respectively.
(d)
The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures.
(e)
Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on New York Mercantile Exchange future prices at December 31, 2007.
(f)
Long-term service agreements include price escalation based on inflation indices.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2007 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company’s 2007 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning environmental regulations and expenditures, financing activities, access to sources of capital, impacts of the adoption of new accounting rules, impacts of the new depreciation study, completion of construction projects, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
•
the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, or particulate matter and other substances, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
•
current and future litigation, regulatory investigations, proceedings, or inquiries, including FERC matters;
•
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
•
variations in demand for electricity, including those relating to weather, the general economy, population, and business growth (and declines), and the effects of energy conservation measures;
•
available sources and costs of fuel;
•
effects of inflation;
•
advances in technology;
•
state and federal rate regulations;
•
the ability to control costs and avoid cost overruns during the development and construction of facilities;
•
internal restructuring or other restructuring options that may be pursued;
•
potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;
•
the ability of counterparties of the Company to make payments as and when due;
•
the ability to obtain new short- and long-term contracts with neighboring utilities;
•
the direct or indirect effect on the Company’s business resulting from terrorist incidents and the threat of terrorist incidents;
•
interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company’s credit ratings;
•
the ability of the Company to obtain additional generating capacity at competitive prices;
•
catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as an avian influenza, or other similar occurrences;
•
the direct or indirect effects on the Company’s business resulting from incidents similar to the August 2003 power outage in the Northeast;
•
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
•
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
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CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2007, 2006, and 2005
Southern Power Company and Subsidiary Companies 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2007, 2006, and 2005
Southern Power Company and Subsidiary Companies 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2007 and 2006
Southern Power Company and Subsidiary Companies 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2007 and 2006
Southern Power Company and Subsidiary Companies 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2007, 2006, and 2005
Southern Power Company and Subsidiary Companies 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2007, 2006, and 2005
Southern Power Company and Subsidiary Companies 2007 Annual Report
The accompanying notes are an integral part of these financial statements.
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NOTES TO FINANCIAL STATEMENTS
Southern Power Company and Subsidiary Companies 2007 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Southern Power Company (the Company) is a wholly-owned subsidiary of Southern Company, which is also the parent company of four traditional operating companies, Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies, Alabama Power Company (APC), Georgia Power Company (GPC), Gulf Power Company, and Mississippi Power Company, are vertically integrated utilities providing electric service in four Southeastern states. The Company constructs, acquires, and manages generation assets and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications services to the traditional operating companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy-related businesses. The investments in synthetic fuels ended on December 31, 2007. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants.
The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC). The Company follows accounting principles generally accepted in the United States. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from those estimates.
The financial statements include the accounts of the Company and its wholly-owned subsidiaries, Southern Company - Florida LLC (SCF), Oleander Power Project, LP (Oleander), DeSoto County Generating Company, LLC (DeSoto), and Southern Power Company - Orlando Gasification LLC (SPC-OG), which own, operate, and maintain the Company’s ownership interests in Plant Stanton Unit A, Plant Oleander, Plant DeSoto, and construct the combined cycle for the Orlando Utilities Commission (OUC), respectively. See Note 2 under “DeSoto and Rowan Acquisitions” and “Oleander Acquisition” and Note 4 under “IGCC” for further information. All intercompany accounts and transactions have been eliminated in consolidation.
Reclassifications
Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no effect on total assets, net income, or cash flows.
The statements of cash flows has been modified to remove the line presented in prior years as “Tax benefit of stock options” and include these amounts in the line item “Other,net.”
Affiliate Transactions
The Company has an agreement with SCS under which the following services are rendered to the Company at amounts in compliance with FERC regulation: general and design engineering, purchasing, accounting and statistical analysis, finance and treasury, tax, information resources, marketing, auditing, insurance and pension administration, human resources, systems and procedures and other services with respect to business and operations and power pool transactions. SCS also enters into fuel purchase and transportation arrangements and contracts, financial instruments for purposes of hedging, and wholesale energy purchase and sale transactions for the benefit of the Company. Because the Company has no employees, all employee-related charges are rendered at amounts in compliance with FERC regulation under agreements with SCS or the traditional operating companies. Costs for these services from SCS amounted to approximately $125.4 million in 2007, $77.8 million in 2006, and $51.9 million in 2005. Approximately $74.1 million in 2007, $59.7 million in 2006, and $47.8 million in 2005 were general, administrative, operations, and maintenance expenses; the remainder was capitalized to construction work in progress and other assets. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.
In 2003, the Company entered into agreements with APC and GPC under which APC and GPC operated and maintained Plants Dahlberg, Wansley, Franklin, and Harris. GPC also supplied various services for other plants. On August 1, 2007, those agreements were terminated and replaced with service agreements under which APC and GPC provided labor and other specifically requested services to the Company. These services are billed at amounts in compliance with FERC regulation on a monthly basis and are
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NOTES (continued)
Southern Power Company and Subsidiary Companies 2007 Annual Report
recorded as operations and maintenance expenses in the statements of income. For the periods ended December 31, 2007, 2006, and 2005, billings under these agreements totaled approximately $9.2 million, $7.6 million, and $7.1 million, respectively.
Total billings for all purchased power agreements (PPAs) in effect with affiliates totaled $505.2 million, $467.9 million, and $531.5 million in 2007, 2006, and 2005, respectively. Included in these billings were $34.8 million, $36.3 million, and $37.5 million of “Deferred capacity revenues - affiliated” recorded on the balance sheets at December 31, 2007, December 31, 2006, and December 31, 2005, respectively. The Company and the traditional operating companies 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.
The Company and the traditional operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity.
In 2007, the Company sold plots of land in Prattville, Alabama and Chilton County, Alabama to APC. The total sales price was $4.3 million and is recorded in “Sale of property to affiliates” on the statements of cash flows. In addition, the Company sold a turbine rotor to Gulf Power for $7.9 million.
In 2006, the Company sold its membership interests in Cherokee Falls Development of South Carolina LLC to Southern Company’s nuclear development affiliate. The sales price was $15.7 million and is recorded in “Sale of property to affiliates” on the statements of cash flows.
Revenues
Capacity is sold at rates specified under contractual terms and is recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract periods. Energy is generally sold at market-based rates and the associated revenue is recognized as the energy is delivered. Transmission revenues and other fees are recognized as incurred as other operating revenue. Revenues are recorded on a gross basis for all full requirements PPAs. See “Financial Instruments” for additional information.
Significant portions of the Company’s revenues have been derived from certain customers. For the year ended December 31, 2007, GPC accounted for 45.6% of revenues, APC accounted for 6.9% of revenues, and Sawnee Electric Membership Corporation accounted for 5.5% of revenues. For the year ended December 31, 2006, GPC accounted for 52.7% of revenues, APC accounted for 8.2% of revenues, and Flint Electric Membership Corporation accounted for 4.6% of revenues. For the year ended December 31, 2005, GPC accounted for 60.1% of revenues and APC accounted for 8.2% of revenues.
The Company has a long-term contract for engineering, procurement, and construction services to build a combined cycle unit for the OUC. Construction activities commenced in 2006 and are expected to be complete by the end of 2010. Revenue and costs are recognized using the percentage-of-completion method. The Company utilizes the cost-to-cost approach as this method is less subjective than relying on assessments of physical progress. The percentage of completion represents the percentage of the total costs incurred to the estimated total cost of the contract. Revenues and costs are recognized by applying this percentage to the total revenues and estimated costs of the contract.
Fuel Costs
Fuel costs are expensed as the fuel is consumed.
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.
In accordance with Financial Accounting Standards Board (FASB) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), the Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information on the effect of adopting FIN 48.
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NOTES (continued)
Southern Power Company and Subsidiary Companies 2007 Annual Report
Property, Plant, and Equipment
The Company’s depreciable property, plant, and equipment consist entirely of generation assets.
Property, plant, and equipment is stated at original cost. Original cost includes materials, direct labor incurred by contractors and affiliated companies, minor items of property, and interest capitalized. Interest is capitalized on qualifying projects during the development and construction period. The cost to replace significant items of property defined as retirement units is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred.
Depreciation
Depreciation of the original cost of assets is computed under the straight-line method and applies a composite depreciation rate based on the assets’ estimated useful lives determined by the Company. The primary assets in property, plant, and equipment are power plants, all of which have an estimated useful life of 35 years, except combustion turbines at Plant Dahlberg, Plant Oleander, Plant Rowan, and Plant DeSoto, all of which have an estimated useful life of 40 years. These lives reflect a composite of the significant components (retirement units) that make up the plants. Depreciation studies are conducted periodically to update the composite rates.
A depreciation study was completed and the applicable remaining plant lives and associated depreciation rates were revised in March 2006. This change in estimate was due to revised useful life assumptions for certain components of plant in service. Depreciation rates by generating facility increased from a range of 2.5% to 2.9% to an adjusted range of 2.8% to 3.8%. These changes increased depreciation and reduced net income. The result of these changes decreased 2006 net income by $3.8 million.
When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its cost is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the accounts and a gain or loss is recognized.
Asset Retirement Obligations and Other Costs of Removal
The present value of the ultimate costs for an asset’s future retirement is recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life.
At December 31, 2007, the Company had no material liability for asset retirement obligations.
Interest Capitalized
Interest related to the construction of new facilities is capitalized in accordance with standard interest capitalization requirements per FASB Statement No. 34, “Capitalization of Interest Cost.”
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on 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 estimating the fair value of the assets and recording a loss for the amount 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.
Deferred Project Development Costs
The Company capitalizes project development costs once it is determined that it is probable that a specific site will be acquired and a power plant constructed. These costs include professional services, permits, and other costs directly related to the construction of a new project. These costs are generally transferred to construction work in progress upon commencement of construction. The total deferred project development costs were $8.4 million at December 31, 2007, $1.3 million at December 31, 2006, and $3.8 million at
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December 31, 2005.
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 costs of generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
Fuel Inventory
Fuel inventory includes the cost of oil and emission allowances. The Company maintains minimal oil levels for use at Plant Dahlberg, Plant Oleander, Plant DeSoto, and Plant Rowan. Inventory is maintained using the weighted average cost method. Fuel inventory and emissions allowances are recorded at actual cost when purchased and then expensed at weighted average cost as used.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities and are measured at fair value. Substantially all of the Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are exempt from fair value accounting requirements and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions. This results in the deferral of related gains and losses in other comprehensive income until the hedged transactions occur. Any ineffectiveness is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income.
The Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk.
The Company’s financial instruments for which the carrying amounts did not equal fair value at December 31 were as follows:
The fair values were based on either closing market prices or closing prices of comparable instruments.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income and changes in the fair value of qualifying cash flow hedges, less income taxes and reclassifications of amounts included in net income.
2. ACQUISITIONS
Oleander Acquisition
In June 2005, the Company acquired all of the outstanding general and limited partnership interests of Oleander from subsidiaries of Constellation Energy Group, Inc. The results of Oleander’s operations have been included in the Company’s consolidated financial statements since that date. The Company’s acquisition of the general and limited partnership interests in Oleander was pursuant to a Purchase and Sale Agreement dated April 8, 2005, for an aggregate total cost of approximately $218.1 million, including
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approximately $11.9 million of working capital and other adjustments. At the time of acquisition, Plant Oleander, a dual-fueled generating plant in Brevard County, Florida, had a nameplate capacity of 628 megawatts (MW). The Oleander acquisition was in accordance with the Company’s overall regional growth strategy.
Subsequent to the acquisition, the Company completed construction of Plant Oleander Unit 5 in December 2007. This unit is a combustion turbine with a nameplate capacity of 163 MW and is contracted to provide annual capacity for a PPA with the Florida Municipal Power Agency from 2007 through 2027.
Desoto and Rowan Acquisitions
Effective June 1, 2006, the Company acquired all of the outstanding membership interests of DeSoto County Generating Company, LLC (DeSoto) from a subsidiary of Progress Energy, Inc. The results of DeSoto’s operations have been included in the Company’s consolidated financial statements since that date. The Company’s acquisition of the membership interest in DeSoto was pursuant to an agreement dated May 8, 2006, for an aggregate total cost of $79.7 million. DeSoto owns a dual-fired generating plant near Arcadia, Florida with a nameplate capacity of 344 MW. The DeSoto acquisition was in accordance with the Company’s overall regional growth strategy.
Effective September 1, 2006, the Company acquired all of the outstanding membership interests of Rowan County Power, LLC (Rowan) from a subsidiary of Progress Energy, Inc. Rowan was merged into the Company, and the results of Rowan’s operations have been included in the Company’s consolidated financial statements since that date. The Company’s acquisition of the membership interests in Rowan was pursuant to an agreement dated May 8, 2006 for an aggregate total cost of $329.5 million. Through the Rowan acquisition, the Company owns a dual-fired generating plant near Salisbury, North Carolina with a nameplate capacity of 986 MW. The Rowan acquisition was in accordance with the Company’s overall regional growth strategy.
The pro forma data of the Company below is unaudited and gives effect to the DeSoto and Rowan plant acquisitions as if they had occurred at January 1, 2005. The unaudited pro forma financial information is not intended to represent or be indicative of the consolidated results of operations or financial condition of the Company that would have been reported had the acquisitions been completed as of the dates presented nor should be taken as representative of any future consolidated results of operations or financial condition of the Company.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against the Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.
In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales
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by the Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level.
In late June and July 2007, hearings were held in this proceeding and the presiding administrative law judge issued an initial decision on November 9, 2007 regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the Company to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates, and could also result in refunds of up to $0.7 million, plus interest. The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter.
On June 21, 2007, the FERC issued its final rule regarding market-based rate authority. The FERC generally retained its current market-based rate standards. The impact of this order and its effect on the generation dominance proceeding cannot now be determined.
Intercompany Interchange Contract
The majority of the Company’s generation fleet is operated under the Intercompany Interchange Contract (IIC), as approved by the FERC. The IIC also governs the operation of the Southern Company generation fleet (Southern Pool). In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies, the Company, and SCS, as agent, under the terms of which the Southern Pool is operated, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining the Company as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of the Company, the FERC authorized the Company’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct.
In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms and Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of the Company. Southern Company filed with the FERC in November 2006 a compliance plan in connection with the order. On April 19, 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. On November 19, 2007, Southern Company notified the FERC that the plan had been implemented and the FERC division of audits subsequently began an audit pertaining to compliance implementation and related matters, which is ongoing. The Company’s cost of implementing the compliance plan, including the modifications, is expected to be approximately $8 million annually.
4. JOINT OWNERSHIP AGREEMENTS
Plant Stanton A
The Company is a 65% owner of Plant Stanton A, a combined-cycle project with a nameplate capacity of 630 MW. The unit is co-owned by OUC (28%), Florida Municipal Power Agency (3.5%), and Kissimmee Utility Authority (3.5%). The Company has a service agreement with SCS whereby SCS is responsible for the operation and maintenance of Plant Stanton A. As of December 31, 2007, $150.7 million was recorded in plant in service with associated accumulated depreciation of $18.7 million. These amounts represent the Company’s share of the total plant assets and each owner must provide its own financing. The Company’s proportionate share of Plant Stanton A’s operating expense is included in the corresponding operating expenses in the statements of income.
IGCC
In December 2005, the Company and the OUC executed definitive agreements for development of a 285-MW integrated coal gasification combined cycle project in Orlando, Florida. The definitive agreements provided that the Company would own at least 65% of the gasifier portion of the IGCC project. OUC would own the remainder of the gasifier portion and 100% of the combined cycle portion of the IGCC project. The Company signed cooperative agreements with the U.S. Department of Energy (DOE) that provided up to $293.75 million in grant funding for the gasification portion of this project. The IGCC project was expected to begin commercial operation in 2010. Due to continuing uncertainty surrounding potential state regulations relating to greenhouse gas emissions, the Company and OUC mutually agreed to terminate the construction of the gasifier portion of the IGCC project in November 2007. The Company will continue construction of the gas-fired combined cycle generating facility for OUC. The Company recorded a loss in the fourth quarter 2007 of approximately $17.6 million related to cancellation of the gasifier portion of the IGCC project. This amount is net of reimbursements from OUC and the DOE. This loss consists of the write-off of construction costs of $14.0 million and an accrual for termination costs of $3.6 million. All termination costs are expected to be paid
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in 2008. As part of the termination agreement with OUC, the Company agreed to sell a tract of land in Orange County, Florida to OUC. The Company will record a gain of $6 million on this sale in 2008.
5. INCOME TAXES
Southern Company files a consolidated federal income tax return and combined tax returns for the State of Georgia, the State of Alabama, and the State of Mississippi. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis, and no subsidiary is allocated more expense than would be paid if it filed a separate income tax return. In accordance with Internal Revenue Service (IRS) regulations, each company is jointly and severally liable for the tax liability.
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
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 are the result of property related timing differences. The transfer of the Plant McIntosh construction project to GPC in 2004 resulted in a deferred gain for federal income tax purposes. GPC is reimbursing the Company for the related tax liability balance of $4.6 million. Of this total, $0.4 million is included in the balance sheets in “Receivables - Affiliated companies” and the remainder is included in “Deferred Charges and Other Assets: Other - Affiliated.”
Deferred tax assets consist primarily of timing differences related to the recognition of capacity revenues, and the deferred loss on interest rate swaps reflected in other comprehensive income. The transfer of Plants Dahlberg, Wansley, and Franklin to the Company from GPC in 2001 also resulted in a deferred gain for federal income tax purposes. The Company will reimburse GPC for the related tax asset of $9.1 million. Of this total, $1.3 million is included in the balance sheets in “Accounts payable - Affiliated” and the remainder is included in “Deferred Credits and Other Liabilities: Other - Affiliated.”
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Effective Tax Rate
A reconciliation of the federal statutory tax rate to the effective income tax rate is as follows:
The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to United States production activities as defined in Internal Revenue Code of 1986, as amended, Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for years 2007 through 2009, and a 9% rate applicable for all years after 2009. This increase from 3% in 2006 to 6% in 2007 was one of several factors that increased the Company’s 2007 deduction by $1.2 million over the 2006 deduction. The resulting additional tax benefit was $0.4 million.
Unrecognized Tax Benefits
On January 1, 2007, the Company adopted FIN 48, which requires companies to determine whether it is “more likely than not” that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. It also provides guidance on the recognition, measurement, and classification of income tax uncertainties, along with any related interest and penalties.
Prior to the adoption of FIN 48, the Company had unrecognized tax benefits which were previously accrued under Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies” of approximately $0.2 million. The total $0.2 million in unrecognized tax benefits would impact the Company’s effective tax rate if recognized. For 2007, the total amount of unrecognized tax benefits increased by $1.2 million, resulting in a balance of $1.4 million as of December 31, 2007.
Changes during the year in unrecognized tax benefits were as follows:
Impact on the Company’s effective tax rate, if recognized, was as follows:
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Accrued interest for unrecognized tax benefits:
The Company classifies interest on tax uncertainties as interest expense. Net interest accrued for the year ended December 31, 2007 was $0.1 million. The Company did not accrue any penalties on uncertain tax positions.
The IRS has audited and closed all tax returns prior to 2004. The audits for the state returns have either been concluded, or the statutes or limitations have expired for years prior to 2002.
It is reasonably possible that the amount of the unrecognized benefit with respect to certain of the Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The possible settlement of the production activities deduction methodology and/or the conclusion or settlement of federal or state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
6. FINANCING
Senior Notes
In 2007, the Company did not issue any long-term debt securities. The Company issued a total of $200 million unsecured 30-year senior notes in 2006. The proceeds of the issuance were used to repay a portion of the Company’s short-term indebtedness and for other general corporate purposes, including the Company’s construction program. Long term debt outstanding was $1.3 billion at December 31, 2007 and 2006.
Bank Credit Arrangements
The Company has a $400 million unsecured syndicated revolving credit facility (Facility) expiring in July 2012. The purpose of the Facility is to provide liquidity support to the Company’s commercial paper program and for other general corporate purposes. Borrowings of $13 million were outstanding under the Facility at December 31, 2007.
The Company is required to pay a commitment fee on the unused balance of the Facility. This fee is less than 1/8 of 1%. In 2007 and 2006, the Company incurred approximately $0.4 million and $0.5 million, respectively, in expenses from commitment fees under the Facility. In 2005, the Company incurred expenses of $0.8 million from commitment fees under a previous facility.
The Facility contains a covenant that limits the debt to capitalization ratio to a maximum of 65%, as defined in the Facility. The Facility also contains a cross default provision that would be triggered if the Company defaulted on other indebtedness above a specified threshold. As of December 31, 2007, the Company was in compliance with all such covenants.
Dividend Restrictions
The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
The Facility and the senior note indenture related to certain series of the Company’s senior notes also contain certain limitations on the payment of common stock dividends. No dividends may be paid unless, as of the end of any calendar quarter, the Company’s projected cash flows from fixed priced capacity PPAs (as defined in the agreements) are at least 80% of total projected cash flows for the next 12 months or the Company’s debt to capitalization ratio is no greater than 60%. At December 31, 2007, the Company was in compliance with these ratios and had no restrictions on its ability to pay dividends.
Commercial Paper
The Company has the ability to borrow under a commercial paper program. For the period ended December 31, 2007, the peak commercial paper balance outstanding was $167 million. The average amount outstanding was $95.8 million in 2007. The average
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annual interest rate was 5.5% in 2007. As of December 31, 2007, the commercial paper program had an outstanding balance of $36.7 million. The outstanding balance on December 31, 2006 was $123.8 million.
Financial Instruments
The Company enters into energy related derivatives to hedge exposures to electricity, gas, and other fuel price changes. The Company’s exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. At December 31, 2007, the fair value gains/(losses) of derivative energy contracts was reflected in the financial statements as follows:
Derivatives not qualifying for hedge accounting are reflected in other income on the Company’s consolidated statement of income. Fair value gains or losses for cash flow hedges are recorded in other comprehensive income and reclassified to fuel expense. There were no material amounts reclassified during any year presented. For the year 2008, the reclassifications from other comprehensive income to fuel expense are also expected to be immaterial. There was no significant ineffectiveness recorded in earnings for any period presented. The Company has energy-related hedges in place through 2008. At December 31, 2007, there were approximately $9.4 million of deferred pre-tax realized net hedging gains relating to capitalized costs and revenues during the construction of specific plants. This will be reclassified from other comprehensive income to depreciation and amortization over the remaining life of the respective plants, which is approximately 27 years. For any year presented, the pre-tax gains reclassified from other comprehensive income to depreciation and amortization have been immaterial.
At December 31, 2007, the Company had no interest derivatives outstanding. The Company has deferred losses totaling $65.1 million in other comprehensive income that will be amortized to interest expense through 2016. For the years 2007, 2006, and 2005, approximately $13.3 million, $12.0 million, and $11.2 million, respectively, of pre-tax losses were reclassified from other comprehensive income to interest expense. During 2008, approximately $12.0 million of pre-tax losses are expected to be reclassified from other comprehensive income to interest expense.
7. COMMITMENTS
Construction Program
The Company currently estimates property additions to be $109.1 million, $281.9 million, and $765.4 million in 2008, 2009, and 2010, respectively. There is currently one unit at Plant Franklin actively under construction.
Long-Term Service Agreements
The Company has entered into Long-Term Service Agreements (LTSAs) with General Electric (GE) for the purpose of securing maintenance support for its combined cycle and combustion turbine generating facilities. In summary, the LTSAs provide that GE will perform all planned inspections and certain unplanned maintenance on the covered equipment, which includes the cost of all labor and materials.
Scheduled payments to GE, which are subject to price escalation, are made at various intervals based on actual operating hours or number of gas turbine starts of the respective units. Total remaining payments to GE under these agreements are currently estimated at $1.2 billion over the remaining term of the agreements, which may range up to 40 years. However, the LTSAs contain various cancellation provisions at the Company’s option.
Payments made to GE prior to the performance of any planned inspections or unplanned maintenance are recorded as a prepayment in current assets or deferred charges and other assets on the balance sheets and are recorded as property additions in the statement of cash flows. Inspection and maintenance costs are capitalized or charged to expense based on the nature of the work performed. These transactions are non-cash and are not reflected in the statements of cash flows.
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Fuel and Purchased Power Commitments
SCS, as agent for the traditional operating companies and the Company, has entered into various fuel transportation and procurement agreements to supply a portion of the fuel (primarily natural gas) requirements for the operating facilities. In most cases, these contracts contain provisions for firm transportation costs, storage costs, minimum purchase levels, and other financial commitments.
Natural gas purchase commitments contain given volumes with prices based on various indices at the actual time of delivery. Amounts included in the chart below represent estimates based on the New York Mercantile Exchange future prices at December 31, 2007. Also, the Company has entered into various long-term commitments for the purchase of electricity.
Total estimated minimum long-term obligations at December 31, 2007 were as follows:
Additional commitments for fuel will be required to supply the Company’s future needs.
Acting as an agent for all of Southern Company’s traditional operating companies and the Company, SCS may enter into various types of wholesale energy and natural gas contracts. Under these agreements, each of the traditional operating companies and the Company may be jointly and severally liable. The creditworthiness of the Company is currently inferior to the creditworthiness of the traditional operating companies; therefore, Southern Company has entered into keep-well agreements with each of the traditional operating companies to ensure they will not subsidize nor be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of the Company as a contracting party under these agreements.
Operating Leases
The Company has operating lease agreements with various terms and expiration dates. Total operating lease expenses were $0.5 million, $0.6 million, and $0.7 million for 2007, 2006, and 2005, respectively. At December 31, 2007, estimated minimum rental commitments for noncancelable operating leases were as follows:
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8. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for 2007 and 2006 is as follows:
The Company’s business is influenced by seasonal weather conditions. Fourth quarter 2007 operating income and net income were impacted by the loss on the IGCC project of $17.6 million pretax and $10.7 million after tax.
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PART III
Items 10, 11, 12 (except for “Equity Compensation Plan Information” which is included herein on page III-42), 13, and 14 for Southern Company are incorporated by reference to Southern Company’s definitive Proxy Statement relating to the 2008 Annual Meeting of Stockholders. Specifically, reference is made to “Nominees for Election as Directors,” “Corporate Governance,” and “Section 16(a) Beneficial Ownership Reporting Compliance” for Item 10, “Executive Compensation,” “Compensation Discussion and Analysis,” “Compensation and Management Succession Committee Report,” “Director Compensation,” and “Director Compensation Table” for Item 11, “Stock Ownership Table” for Item 12, “Certain Relationships and Related Transactions” and “Director Independence” for Item 13, and “Principal Public Accounting Firm Fees” for Item 14.
Items 10, 11, 12, 13, and 14 for Alabama Power, Georgia Power, and Mississippi Power are incorporated by reference to the Information Statements of Alabama Power, Georgia Power, and Mississippi Power relating to each of their respective 2008 Annual Meetings of Shareholders. Specifically, reference is made to “Nominees for Election as Directors,” “Corporate Governance,” and “Section 16(a) Beneficial Ownership Reporting Compliance” for Item 10, “Executive Compensation Information,” “Compensation Discussion and Analysis,” “Compensation and Management Succession Committee Report,” “Director Compensation,” and “Director Compensation Table” for Item 11, “Stock Ownership Table” for Item 12, “Certain Relationships and Related Transactions” and “Director Independence” for Item 13, and “Principal Public Accounting Firm Fees” for Item 14.
Items 10, 11, 12, and 13 for Southern Power are omitted pursuant to General Instruction I(2)(c) of Form 10-K.
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Identification of directors of Gulf Power.
Susan N. Story
Fred C. Donovan, Sr. (1)
President and Chief Executive Officer
Age 67
Age 47
Served as Director since 1991
Served as Director since 2003
C. LeDon Anchors (1)
William A. Pullum (1)
Age 67
Age 60
Served as Director since 2001
Served as Director since 2001
William C. Cramer, Jr. (1)
Winston E. Scott (1)
Age 55
Age 57
Served as Director since 2002
Served as Director since 2003
(1) No position other than director.
Each of the above is currently a director of Gulf Power, serving a term running from the last annual meeting of Gulf Power’s shareholders (June 26, 2007) for one year until the next annual meeting or until a successor is elected and qualified.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he or she was or is to be selected as an officer, other than any arrangements or understandings with officers of Gulf Power acting solely in their capacities as such.
III-1
Identification of executive officers of Gulf Power.
Susan N. Story
Theodore J. McCullough
President and Chief Executive Officer
Vice President - Senior Production Officer
Age 47
Age 44
Served as Executive Officer since 2003
Served as Executive Officer since 2007
P. Bernard Jacob
Bentina C. Terry
Vice President - Customer Operations
Vice President - External Affairs and Corporate Services
Age 53
Age 37
Served as Executive Officer since 2003
Served as Executive Officer since 2007
Ronnie R. Labrato*
Vice President and Chief Financial Officer
Age 54
Served as Executive Officer since 2000
*
Mr. Labrato has been named Vice President of Internal Auditing at Southern Company and will resign from his position at Gulf Power to assume his new duties effective April 1, 2008.
Each of the above is currently an executive officer of Gulf Power, serving a term running from the last annual organizational meeting of the directors (July 26, 2007) for one year until the next annual meeting or until a successor is elected and qualified, except for Mr. McCullough whose election was effective August 11, 2007.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he or she was or is to be selected as an officer, other than any arrangements or understandings with officers of Gulf Power acting solely in their capacities as such.
Identification of certain significant employees. None.
Family relationships. None.
Business experience. Unless noted otherwise, each director has served in his or her present position for at least the past five years.
Susan N. Story - President and Chief Executive Officer since 2003. She previously served as Senior Vice President of Southern Power from November 2002 to April 2003; and Executive Vice President of SCS from January 2001 to April 2003.
C. LeDon Anchors - Attorney and President of Anchors Smith Grimsley, Attorneys at Law, Fort Walton Beach, Florida. He is a Director of Beach Community Bank.
William C. Cramer, Jr. - President and Owner of Tommy Thomas Chevrolet, Panama City, Florida.
Fred C. Donovan, Sr. - Chairman and Chief Executive Officer of Baskerville-Donovan, Inc. (an architectural and engineering firm), Pensacola, Florida.
William A. Pullum - President/Director of Bill Pullum Realty, Inc., Navarre, Florida.
Winston E. Scott - Vice President and Deputy General Manager, Engineering and Science Contract Group at Jacobs Engineering, Houston, Texas. He previously served as Executive Director of the Florida Space Authority, Cape Canaveral, Florida, from 2003 to 2006; Professor and Associate Dean with the Florida Agriculture and Mechanical University and Florida State University (FSU) College of Engineering in 2003; and Vice President for Student Affairs at FSU from 2000 to 2003.
III-2
P. Bernard Jacob - Vice President of Customer Operations since 2007. He previously served as Vice President of External Affairs and Corporate Services from 2003 to 2007 and Director of Information Resources Security and Program Management at SCS from 2002 to 2003.
Ronnie R. Labrato - Vice President and Chief Financial Officer since January 2006. He previously served as Vice President, Chief Financial Officer and Comptroller from July 2001 to January 2006.
Theodore J. McCullough - Vice President and Senior Production Officer since August 11, 2007. He previously served as the Manager of Georgia Power’s Plant Branch from December 2003 to August 2007 and Combined Cycle Site Manager of Southern Power’s Plant Franklin from January 2002 to December 2003.
Bentina C. Terry - Vice President of External Affairs and Corporate Services since March 24, 2007. She previously served as the Vice President and Corporate Counsel for Southern Nuclear from January 2005 to March 2007; Area Distribution Manager of Georgia Power from February 2004 through January 2005; and Assistant to the President of Georgia Power from November 2002 to February 2004.
Involvement in certain legal proceedings. None.
Section 16(a) Beneficial Ownership Reporting Compliance. None.
Code of Ethics
The registrants collectively have adopted a code of business conduct and ethics that applies to each director, officer, and employee of the registrants and their subsidiaries. The code of business conduct and ethics can be found on Southern Company’s website located at www.southerncompany.com. The code of business conduct and ethics is also available free of charge in print to any shareholder by requesting a copy from Patricia L. Roberts, Assistant Corporate Secretary, Southern Company, 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308. Any amendment to or waiver from the code of ethics that applies to executive officers and directors will be posted on the website.
Corporate Governance
Southern Company has adopted corporate governance guidelines and committee charters. The corporate governance guidelines and the charters of Southern Company’s Audit Committee, Governance Committee, and Compensation and Management Succession Committee can be found on Southern Company’s website located at www.southerncompany.com. The corporate governance guidelines and charters are also available free of charge in print to any shareholder by requesting a copy from Patricia L. Roberts, Assistant Corporate Secretary, Southern Company, 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308.
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ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
COMPENSATION DISCUSSION AND ANALYSIS
In this Compensation Discussion and Analysis (CD&A) and this Form 10-K, references to the “Compensation Committee” are to the Compensation and Management Succession Committee of the Board of Directors of Southern Company.
GUIDING PRINCIPLES AND POLICIES
Southern Company, through a single executive compensation program for all officers of its subsidiaries, drives and rewards both Southern Company financial performance and individual business unit performance.
This executive compensation program is based on a philosophy that total executive compensation must be competitive with the companies in our industry, must be tied to and motivate our executives to meet our short- and long-term performance goals, and must foster and encourage alignment of executive interests with the interests of our stockholders and our customers. The program generally is designed to motivate all employees, including executives, to achieve operational excellence and financial goals while maintaining a safe work environment.
The executive compensation program places significant focus on rewarding performance. The program is performance-based in several respects:
•
Southern Company’s actual earnings per share (EPS) and Gulf Power’s business unit performance, which includes return on equity (ROE), compared to target performance levels established early in the year, determine the ultimate annual incentive payouts.
•
Southern Company common stock (Common Stock) price changes result in higher or lower ultimate values of stock options.
•
Southern Company’s dividend payout and total shareholder return compared to those of its industry peers lead to higher or lower payouts under the Performance Dividend Program (performance dividends).
In support of the performance-based pay philosophy, we have no general employment contracts with our named executive officers or guaranteed severance, except upon a change in control, and no pay is conditioned solely upon continued employment with any of the named executive officers, other than base salary.
The pay-for-performance principles apply not only to the named executive officers, but to hundreds of Gulf Power employees. The short-term incentive program covers over 1,300 Gulf Power employees, which is almost all of Gulf Power’s employees, and our change in control protection program covers all Gulf Power employees not part of a collective bargaining unit. Stock options and performance dividends cover approximately 265 Gulf Power employees. These programs engage our people in our business, which ultimately is good not only for them, but for Gulf Power’s customers and Southern Company’s stockholders.
OVERVIEW OF EXECUTIVE COMPENSATION COMPONENTS
The executive compensation program for the named executive officers is composed of several components, each of which plays a different role. The table below discusses the intended role of each material pay component, what it rewards, and why we use it. Following the table is additional information that describes how we made 2007 pay decisions.
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Intended Role and What the Element
Pay Element
Rewards
Why We Use the Element
Base Salary
Base salary is pay for competence in the executive role, with a focus on scope of responsibilities.
Market practice.
Provides a threshold level of cash compensation for job performance.
Annual Incentive
Gulf Power’s annual incentive program rewards achievement of operational, EPS, and business unit financial goals.
Market practice.
Focuses attention on achievement of short-term goals that ultimately works to fulfill our mission to customers and leads to increased stockholder value in the long-term.
Long-Term Incentive: Stock Options
Stock options reward price increases in Common Stock over the market price on the date of grant, over a 10-year term.
Performance-based compensation.
Aligns executives’ interests with those of Southern Company’s stockholders.
Market practice.
Long-Term Incentive: Performance Dividends
Performance dividends provide cash compensation dependent on the number of stock options held at year end, Southern Company’s declared dividends during the year, and Southern Company’s four-year total shareholder return versus industry peers.
Performance-based compensation.
Enhances the value of stock options and focuses executives on maintaining a significant dividend yield for Southern Company’s stockholders.
Aligns executives’ interests with Southern Company’s stockholders’ interests since payouts are dependent on performance, defined as Common Stock performance vs. industry peers.
Market practice.
Relocation Incentive
Lump sum payment of 10% of base salary provides incentive to geographically relocate.
Enhances the value of the relocation program perquisite.
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Intended Role and What the Element
Pay Element
Rewards
Why We Use the Element
Retirement Benefits
The Deferred Compensation Plan provides the opportunity to defer to future years all or part of base salary and annual incentive in either a prime interest rate or Common Stock account.
Permitting compensation deferral is a cost-effective method of providing additional cash flow to Gulf Power while enhancing the retirement savings of executives.
Executives participate in employee benefit plans available to all employees of Gulf Power, including a 401(k) savings plan and the funded Southern Company Pension Plan (Pension Plan).
The purpose of these supplemental plans is to eliminate the effect of tax limitations on the payment of retirement benefits.
The Supplemental Benefit Plan counts pay, including deferred salary, ineligible to be counted under the Pension Plan and the 401(k) plan due to Internal Revenue Service rules.
Represents an important component of competitive market-based compensation in Southern Company’s peer group and generally.
The Supplemental Executive Retirement Plan counts short-term incentive pay above 15% of base salary for pension purposes.
Perquisites and Other Personal Benefits
Personal financial planning maximizes the perceived value of our executive compensation program to executives and allows executives to focus on Gulf Power’s operations.
Perquisites benefit both Gulf Power and executives, at low cost to Gulf Power.
Home security systems lower our risk of harm to executives.
Club memberships are provided primarily for business use.
Relocation benefits cover the costs associated with geographic relocation at the request of the employer.
Post-Termination Pay
Change in control plans provide severance pay, accelerated vesting, and payment of short- and long-term incentive awards upon a change in control of Gulf Power or Southern Company coupled with involuntary termination not for “Cause” or a voluntary termination for “Good Reason.”
Providing protections to senior executives upon a change in control minimizes disruption during a pending or anticipated change in control.
Payment and vesting occur only upon the occurrence of both an actual change in control and loss of the executive’s position.
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MARKET DATA
For the named executive officers, we review compensation data from large, publicly-owned electric and gas utilities. The data was developed and analyzed by Hewitt Associates, one of the compensation consultants retained by the Compensation Committee. The companies included each year in the primary peer group are those whose data is available through the consultant’s database. Those companies are drawn from this list of regulated utilities of $2 billion in revenues and up. Proxy data for this entire list of companies below also is used. No other companies’ data are used in our market-pay benchmarking.
Allegheny Energy, Inc.
Entergy Corporation
PNM Resources, Inc.
Alliant Energy Corporation
Exelon Corporation
PPL Corporation
Ameren Corporation
FirstEnergy Corp.
Progress Energy, Inc.
American Electric Power Company, Inc.
FPL Group, Inc.
Public Service Enterprise
Group Incorporated
Centerpoint Energy, Inc.
Great Plains Energy Incorporated
Puget Energy, Inc.
CMS Energy Corporation
Hawaiian Electric Industries, Inc.
SCANA Corporation
Consolidated Edison, Inc.
KeySpan Corporation
Sempra Energy
Constellation Energy Group, Inc.
NiSource Inc.
Sierra Pacific Resources
Dominion Resources, Inc.
Northeast Utilities
TECO Energy, Inc.
DTE Energy Company
NSTAR
TXU Corp.
Duke Energy Corporation
OGE Energy Corp.
Vectren Corporation
Edison International
Pepco Holdings, Inc.
Wisconsin Energy Corporation
Energy East Corporation
PG&E Corporation
Pinnacle West Capital Corporation
WPS Resources Corporation
Xcel Energy Inc.
Southern Company is one of the largest U.S. utility companies in revenues and market capitalization, and its largest business units are some of the largest in the industry as well. For that reason, the consultant size-adjusts the market data in order to fit it to the scope of our business.
In using this market data, market is defined as the size-adjusted 50th percentile of the data, with a focus on pay opportunities at target performance (rather than actual plan payouts). Gulf Power specifically looks at the market data for chief executive officer positions and other positions in terms of scope of responsibilities, that most closely resemble the positions held by the named executive officers. Based on that data, Gulf Power establishes a total target compensation opportunity for each named executive officer. Total target compensation opportunity is the sum of base salary, annual incentive payout (at the target performance level), stock option awards at a target value, and performance dividend payout (at the target performance level). Actual compensation paid may be more or less than the total target compensation opportunity based on actual performance above or below target performance levels. As a result, the compensation program is designed to result in payouts that are market-appropriate given Gulf Power’s performance for the year or period.
We did not target a specified weight for base salary or annual or long-term incentives as a percent of total target compensation opportunities, nor did amounts realized or realizable from prior compensation serve to increase or decrease 2007 compensation amounts. Total target compensation opportunities for senior management as a group are managed to be at the median of the market for companies our size and in our industry. The total target compensation opportunities established in 2007 for each named executive officer is shown below.
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As is our long-standing practice, the salary levels shown above were not effective before March 2007. Therefore, the amounts reported in the Summary Compensation Table are lower because that table reports actual amounts paid in 2007. For purposes of comparing the value of our compensation program to the market data, stock options are valued at 15%, and performance dividend targets at 10%, of the average daily Common Stock price for the year preceding the grant, both of which represent risk-adjusted present values on the date of grant and are consistent with the methodologies used to develop the market data. For the 2007 grant of stock options and the performance dividend targets established for the 2007 - 2010 performance period, this value was $8.515 per stock option granted. In the long-term incentive column, 60% of the value shown is attributable to stock options and 40% attributable to performance dividends. The stock option value used for market data comparisons exceeds the value reported in the Grants of Plan-Based Awards Table because the value above is calculated assuming that the options are held for their full 10-year term. The calculation of the Black-Scholes value reported in the Grants of Plan-Based Awards Table uses historical holding period averages of approximately five years.
§
As discussed above, the Compensation Committee targets total target compensation opportunities for executives as a group at market. Therefore, some executives may be paid somewhat above and others somewhat below market. This practice allows for minor differentiation based on time in the position, scope of responsibilities, and individual performance. The differences in the total pay opportunities for each named executive officer are based almost exclusively on the differences indicated by the market data for persons holding similar positions. Ms. Terry and Mr. McCullough were promoted into their current positions during 2007. Therefore, their respective total target compensation opportunities were lower than they would have been had they been in their current positions for the entire year. The average total target compensation opportunities for the named executive officers for 2007 were slightly less than the market data described above. However, because of the use of market data from a large number of peer companies for positions that are not identical in terms of scope of responsibility from company to company, we do not consider this difference material and we continue to believe that our compensation program is market-appropriate.
§
In 2007, the Compensation Committee engaged an additional executive compensation consulting firm to conduct a broad assessment of Southern Company’s executive compensation program. Benchmarking data as well as actual levels of payouts made at peer companies was reviewed. The consulting firm was directed to review the level of total target pay opportunities, the weight of each primary pay component, and the annual and long-term incentive goal metrics. Based on the findings in this review, Gulf Power and the Compensation Committee continue to believe that our executive compensation program provides the appropriate level and mix of compensation for the senior management of Gulf Power, including the named executive officers.
§
In 2004, the Compensation Committee received from its executive compensation consulting firm a detailed comparison of our executive benefits program to the benefits of a group of other large utilities and general industry companies. The results indicated that Gulf Power’s executive benefits program was slightly below market. The Compensation Committee plans to have this study updated in 2008.
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DESCRIPTION OF KEY COMPENSATION COMPONENTS
2007 Base Salary
The named executive officers are each within a position level with a base salary range that is established under the direction of the Compensation Committee using the market data described above. Also considered in recommending the specific base salary level for each named executive officer is the need to retain an experienced team, internal equity, time in position, and individual performance. This analysis of individual performance included the degree of competence and initiative exhibited and the individual’s relative contribution to the results of operations in prior years.
Base salaries for Messrs. Jacob and Labrato and Ms. Terry were recommended by Ms. Susan N. Story, the Gulf Power President and Chief Executive Officer, to Mr. David M. Ratcliffe, the Southern Company President and Chief Executive Officer. Mr. McCullough currently serves, and Ms. Manuel served during a portion of 2007, as both executive officers of Gulf Power and of Southern Company’s generation business unit (Southern Company Generation). Their base salaries were recommended by an Executive Vice President of Southern Company Generation, with input from Ms. Story, to the President of Southern Company Generation. Ms. Story’s base salary is approved by Mr. Ratcliffe.
The actual base salary levels set for each of the named executive officers were set within the pre-established salary ranges.
2007 Incentive Compensation
Achieving Operational and Financial Goals - Our Guiding Principle for Incentive Compensation
Our number one priority is to provide our customers outstanding reliability and superior service at low prices while achieving a level of financial performance that benefits Southern Company’s stockholders in the short and long term.
In 2007, we strove for and rewarded:
•
Continued industry-leading reliability and customer satisfaction, while maintaining our low retail prices relative to the national average; and
•
Meeting increased energy demand with the best economic and environmental choices.
In 2007, we also focused on and rewarded:
•
Southern Company EPS Growth - A continuation of growing EPS an average of 5% per year from a base, excluding earnings from synthetic fuel investments, established in 2002. The target goal shown below is 5% greater than the goal established for 2006.
•
Gulf Power ROE in the top quartile of comparable electric utilities.
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•
Common Stock dividend growth.
•
Long-term, risk-adjusted Southern Company total shareholder return.
•
Financial Integrity - An attractive risk-adjusted return, sound financial policy, and a stable “A” credit rating.
The incentive compensation program is designed to encourage Gulf Power to achieve these goals.
The Southern Company Chief Executive Officer with the assistance of Southern Company’s Human Resources staff recommends to the Compensation Committee program design and award amounts for senior executives.
2007 Annual Incentive Program
Program Design The Performance Pay Program is Southern Company’s annual incentive plan. Almost all employees of Gulf Power are participants, including the named executive officers, a total of over 1,300 Gulf Power participants.
The performance measured by the program uses goals set at the beginning of each year by the Compensation Committee.
An illustration of the annual incentive goal structure for 2007 is provided below.
•
Operational goals for 2007 were safety, customer service, plant availability, transmission and distribution system reliability, inclusion, and, for Southern Company Generation, also net income. Each of these operational goals is explained in more detail under “Goal Details” below. The result of all operational goals is averaged and multiplied by the bonus impact of the EPS and business unit financial goals. The amount for each goal can range from 0.90 to 1.10 or 0.00 if a threshold performance level is not achieved as more fully described below. The level of achievement for each operational goal is determined and the results are averaged.
•
Southern Company EPS is weighted at 50% of the financial goals. EPS is defined as earnings from continuing operations divided by average shares outstanding during the year, excluding earnings from synthetic fuel investments. The EPS performance measure is applicable to all participants in the Performance Pay Program, including the named executive officers.
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•
Business unit financial performance is weighted at 50% of the financial goals. Gulf Power’s financial performance goal is ROE, which is defined as Gulf Power’s net income divided by average equity for the year. For Southern Company Generation, it is calculated using a corporate-wide weighted average of all the business unit financial performance goals, including primarily the ROE of Gulf Power and affiliated companies, Alabama Power, Georgia Power, and Mississippi Power. For Mr. McCullough, the business unit financial goal was weighted 30% Gulf Power ROE and 20% Southern Company Generation financial goal. Ms. Manuel’s business unit financial goal was the same as that for Mr. McCullough until she assumed her current position at an affiliated company. Ms. Manuel is not a named executive officer in her current position. Her business unit financial goal at year-end 2007 was based entirely on the Southern Company Generation financial goal.
The Compensation Committee may make adjustments, both positive and negative, to goal achievement for purposes of determining payouts. Such adjustments include the impact of items considered one time or outside of normal operations or not anticipated in the business plan when the earnings goal was established, and of sufficient magnitude to warrant recognition. For the payouts based on 2007 performance, no adjustments materially impacted the payouts to the named executive officers.
Under the terms of the program, no payout can be made if Southern Company’s current earnings are not sufficient to fund its Common Stock dividend at the same level or higher than the prior year.
Goal Details
Operational Goals:
Customer Service - Gulf Power uses customer satisfaction surveys to evaluate its performance. The survey results provide an overall ranking for Gulf Power, as well as a ranking for each customer segment: residential, commercial, and industrial.
Reliability - Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected capital expenditures.
Availability - Peak season equivalent forced outage rate 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.
Safety - Southern Company’s Target Zero program is focused on continuous improvement in having a safe work environment. The performance is measured by the Occupational Safety and Health Administration recordable incident rate.
Inclusion/Diversity - The inclusion program seeks to improve our inclusive workplace. This goal includes measures for work environment (employee satisfaction survey), representation of minorities and females in leadership roles, and supplier diversity.
Southern Company capital expenditures “gate” or threshold goal - Southern Company strived to manage total capital expenditures for the participating business units at or below $3.8 billion for 2007, excluding nuclear fuel. If the capital expenditure target is exceeded, total operational goal performance is capped at 0.90 for all business units, regardless of the actual operational goal results. Adjustments to the goal may occur due to significant events not anticipated in Southern Company’s business plan established early in 2007, such as acquisitions or disposition of assets, new capital projects, and other events.
For Ms. Manuel, the Southern Company Generation operational goals are applied rather than those for Gulf Power. These goals included availability, safety, inclusion, and Southern Company Generation net income. For Mr. McCullough, the operational goals are weighted 60% based on Gulf Power’s operational goals and 40% based on Southern Company Generation’s operational goals.
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The range of performance levels established for the operational goals are detailed below.
EPS and Business Unit Financial Performance:
The range of EPS and business unit financial goals for 2007 is shown below. The ROE goal varies from the allowed retail ROE range due to state regulatory accounting requirements, wholesale activities, other non-jurisdictional revenues and expenses, and other activities not subject to state regulation.
2007 Achievement
Each named executive officer had a target annual incentive opportunity, based on his or her position, set by the Compensation Committee at the beginning of 2007. Targets are set as a percentage of base salary. Ms. Story’s target was set at 60%. For Messrs. Jacob and Labrato it was set at 45%. For Ms. Manuel it was initially set at 40% based on her position level and increased to 45% in August 2007 when she assumed her current position. For Mr. McCullough it was initially set at 35% and was increased to 40% in August 2007 when he assumed his current position. For Ms. Terry it was initially set at 40% and was increased to 45% in March 2007 when she assumed her current position. Actual payouts were determined by adding the payouts derived from EPS and business unit financial performance goal achievement for 2007 and multiplying that sum by the result of the operational goal achievement. The gate goal target was not exceeded and therefore did not affect payouts. Actual 2007 goal achievement is shown in the following table.
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For Ms. Manuel, the Total Payout Factor was based 50% on EPS and 50% on Southern Company Generation performance. For Mr. McCullough, the Total Payout Factor was based 50% on EPS, 30% on Gulf Power performance, and 20% on Southern Company Generation performance. Ms. Manuel’s was adjusted by the Southern Company Generation operational goal multiplier and Mr. McCullough’s was adjusted based on a weighted average of the Gulf Power operational goal multiplier (60%) and the Southern Company Generation operational goal multiplier (40%).
Note that the Total Payout Factor may vary from the Total Weighted Performance multiplied by the operational goal multiplier due to rounding. To calculate the annual incentive payout amount, the target opportunity (annual incentive target times base salary) is multiplied by the Total Payout Factor. For Mss. Manuel and Terry and Mr. McCullough it is prorated based on the period of time they served in different positions as described above.
Annual incentive payouts were determined using EPS and business unit financial performance results. The EPS results used differ somewhat from the results reported in Southern Company’s financial statements in the Southern Company’s 2007 Annual Report to Stockholders. Gulf Power’s ROE results used for annual incentive calculations differ somewhat from the results reported by Gulf Power in Item 6 herein. These differences are described below.
EPS, excluding earnings from synthetic fuel investments - In 2007, Southern Company’s synthetic fuel investments generated tax credits as a result of synthetic fuel production. Due to higher oil prices over the past two years, such tax credits were partially phased out and one synfuel investment was terminated in 2006. These tax credits were no longer available after December 31, 2007. Southern Company management uses EPS, excluding earnings from synthetic fuel investments, to evaluate the performance of Southern Company’s ongoing business activities. We believe the presentation of earnings and EPS, excluding the results of the synthetic fuel investments, also is useful for investors because it provides additional information for purposes of comparing our performance for such periods. For 2007, reported EPS was $2.29 per share including earnings from synthetic fuel investments, and $2.21 per share excluding earnings from synthetic fuel investments. As established by the Compensation Committee in early 2007, the annual incentive goal for 2007 measured the EPS performance, excluding earnings from synthetic fuel investments.
The 2007 reported ROE for Gulf Power was 12.32%. ROE performance for the annual incentive calculation was 13.25%, due to an adjustment made to mitigate the ROE impact of losses under certain wholesale contracts. This adjustment was approved by the Compensation Committee at the time the ROE goal for Gulf Power was established in early 2007.
Actual performance exceeded the target performance levels established by the Compensation Committee in early 2007; therefore, the payout levels also exceeded the target pay opportunities that were established. More information on how target pay opportunities are established is provided under the section entitled “Market Data” in this CD&A.
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The table below shows the pay opportunity set in early 2007 for the annual incentive payout at target-level performance and the actual payout based on the actual performance shown above.
Stock Options
Options to purchase Common Stock are granted annually and were granted in 2007 to the named executive officers and about 265 other employees of Gulf Power. Options have a 10-year term, vest over a three-year period, fully vest upon retirement or termination of employment following a change in control and expire at the earlier of five years from the date of retirement or the end of the 10-year term.
Stock option award sizes for 2007 were calculated using guidelines set by the Compensation Committee as a percent of base salary. These guidelines are kept stable from year to year unless the market data indicates a clear need to change them.
The number of options granted is the guideline amount divided by Southern Company’s average daily Common Stock price for the 12 months preceding the grant. This is done to mitigate volatility in the number of options granted and to provide a standard grant methodology.
The calculation of the 2007 stock option grants for the named executive officers is shown below.
The guideline percent is based on the positions held at the time grants are made, which were different for Ms. Manuel, Ms. Terry, and Mr. McCullough from the positions held as of year-end 2007. Also, stock option grants were made based on salaries in effect on March 1, 2007.
More information about the option program is contained in the Grant of Plan Based Awards Table and the information accompanying it.
Performance Dividends
All option holders, including the named executive officers, can receive performance-based dividend equivalents on stock options held at the end of the year. Dividend equivalents can range from 0% to 100% of the Common Stock dividend paid during the year per option held at the end of the year. Actual payout will depend on Southern Company’s total shareholder return over a four-year performance measurement period compared to a group of other
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electric and gas utility companies. The peer group is determined at the beginning of each four-year performance measurement period. The peer group varies from the “Market Data” peer group due to the timing and criteria of the peer selection process. The peer group for performance dividends is set by the Compensation Committee at the beginning of the four-year measurement period. However, despite these timing differences, there is substantial overlap in the companies included.
Total shareholder return is calculated by measuring the ending value of a hypothetical $100 invested in each company’s common stock at the beginning of each of 16 quarters.
No performance dividends are paid if Southern Company’s earnings are not sufficient to fund a Common Stock dividend at least equal to that paid in the prior year.
2007 Payout
The peer group used to determine the 2007 payout for the 2004-2007 performance measurement period was made up of utilities with revenues of $2 billion or more with regulated revenues of 70% or more. Those companies are listed below.
Allegheny Energy, Inc.
Exelon Corporation
Progress Energy, Inc.
Alliant Energy Corporation
FirstEnergy Corporation
Public Service Enterprise Group Incorporated
Ameren Corporation
FPL Group, Inc.
Puget Energy, Inc.
American Electric Power Company, Inc.
NiSource Inc.
SCANA Corporation
Avista Corporation
Northeast Utilities
Sempra Energy
Consolidated Edison, Inc.
NorthWestern Corporation
Sierra Pacific Resources
DTE Energy Company
NSTAR
Westar Energy, Inc.
Energy East Corporation
OGE Energy Corp.
Wisconsin Energy Corporation
Entergy Corporation
Pepco Holdings, Inc.
Xcel Energy Inc.
Pinnacle West Capital
Corporation
The scale below determined the percent of the full year’s dividend paid on each option held at December 31, 2007 based on the 2004-2007 performance measurement period. Payout for performance between points was interpolated on a straight-line basis.
The above payout scale, when established in 2004, paid 25% of the dividend at the 30th percentile and zero below that. The scale was extended to the 10th percentile on a straight-line basis by the Compensation Committee in October 2005, in order to avoid the earnings volatility and employee relations issues that the payout cliff created.
Total shareholder return was calculated by measuring the ending value of a hypothetical $100 invested in each company’s stock at the beginning of each of 16 quarters.
Southern Company’s total shareholder return performance during the four-year period ending with 2007 was the 39th percentile, resulting in a payout of 36% of the full year’s Common Stock dividend, or $0.58. This figure was multiplied by each named executive officer’s outstanding stock options at December 31, 2007 to calculate the payout under the program. The amount paid is included in the Non-Equity Incentive Plan Compensation Column in the Summary Compensation Table.
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2010 Opportunity
The peer group for the 2007-2010 performance measurement period (which will be used to determine the 2010 payout) is made up of utility companies with revenues of $1.2 billion or more with regulated revenues of approximately 60% or more. Those companies are listed below.
The guideline used to establish the peer group for the 2004-2007 performance measurement period was somewhat different from that used in 2006 to establish the peer group for the 2007-2010 performance measurement period. The guideline for inclusion in the peer group is reevaluated annually as needed to assist in identifying 25 to 30 companies similar to Southern Company. While the guideline does vary somewhat, 25 of the 29 companies in the peer group for the 2004-2007 performance measurement period also were in the peer group established for the 2007-2010 period.
Allegheny Energy, Inc.
Edison International
Progress Energy, Inc.
Alliant Energy Corporation
Energy East Corporation
Puget Energy, Inc.
Ameren Corporation
Entergy Corporation
SCANA Corporation
American Electric Power Company, Inc.
Exelon Corporation
Sempra Energy
Aquila, Inc.
FPL Group, Inc.
Sierra Pacific Resources
Avista Corporation
Hawaiian Electric
TECO
Centerpoint Energy, Inc.
NiSource Inc.
UIL Holdings
CMS Energy Corporation
Northeast Utilities
Unisource
Consolidated Edison, Inc.
NSTAR
Vectren Corporation
DPL Inc.
Pepco Holdings, Inc.
Westar Energy, Inc.
DTE, Inc.
PG&E Corporation
Wisconsin Energy Corporation
Duke Energy
Pinnacle West Capital Corporation
Xcel Energy Inc.
The scale below will determine the percent of the full year’s dividend paid on each option held at December 31, 2010, based on the 2007-2010 performance measurement period. Payout for performance between points is interpolated on a straight-line basis.
See the Grants of Plan-Based Awards Table and the accompanying information following it for more information about threshold, target and maximum payout opportunities for the 2007-2010 Performance Dividend Program.
Timing of Incentive Compensation
As discussed above, Southern Company EPS and Gulf Power’s financial performance goals for the 2007 annual incentive program were established at the February 2007 Compensation Committee meeting. Annual stock option grants were also made at that meeting. The establishment of incentive compensation goals and the granting of stock options were not timed with the release of non-public material information. This procedure was consistent with prior practices. Stock option grants are made to new hires or newly-eligible participants on preset, regular quarterly dates that were approved by the Compensation Committee. The exercise price of options granted to employees in 2007 was the closing price of the Common Stock on the date of grant.
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Post-Employment Compensation
As mentioned above, we provide certain post-employment compensation to employees, including the named executive officers:
Retirement Benefits
Generally, all full-time employees of Gulf Power, including the named executive officers, participate in our funded Pension Plan after completing one year of service. Normal retirement benefits become payable when participants both attain age 65 and complete five years of participation. We also provide unfunded benefits that count salary and short-term incentive pay that is ineligible to be counted under the Pension Plan. (These plans are the Supplemental Benefit Plan and the Supplemental Executive Retirement Plan that are mentioned in the chart on pages III-27 through III-28 of this CD&A.) See the Pension Benefits Table and the information accompanying it for more information about pension-related benefits.
Gulf Power also provides the Deferred Compensation Plan which is an unfunded plan that permits participants to defer income as well as certain federal, state, and local taxes until a specified date or their retirement, disability, death, or other separation from service. Up to 50% of base salary and up to 100% of the annual incentive and performance dividends may be deferred, at the election of eligible employees. All of the named executive officers are eligible to participate in the Deferred Compensation Plan. See the Nonqualified Deferred Compensation Table and the information accompanying it for more information about the Deferred Compensation Plan.
Change in Control Protections
The Compensation Committee approved the change in control protection program in 1998. The program provides some level of severance benefits to all employees not part of a collective bargaining unit, if the conditions of the program are met, as described below. The Compensation Committee established this program and the levels of severance amount in order to provide certain compensatory protections to executives upon a change in control and thereby allow them to negotiate aggressively with a prospective purchaser. Providing such protections to our employees in general minimizes disruption during a pending or anticipated change in control. For all participants, payment and vesting occur only upon the occurrence of both an actual change in control and loss of the individual’s position.
Change in control protections, including severance pay and, in some situations, vesting or payment of long-term incentive awards, are provided upon a change in control of Southern Company or Gulf Power coupled with an involuntary termination not for “Cause” or a voluntary termination for “Good Reason.” This means there is a “double trigger” before severance benefits are paid; i.e., there must be both a change in control and a termination of employment.
If the conditions described above are met, the named executive officers are entitled to severance payments equal to two or three times their base salary plus the annual incentive amount assuming target-level performance. Most officers, including the Gulf Power’s named executive officers, are entitled to severance payments equal to two times their base salary plus the annual incentive amount assuming target-level performance. Ms. Story is entitled to the larger amount. These amounts are consistent with that provided by other companies of our size and in our industry and were established based on market-data provided to the Compensation Committee from its compensation consultant.
More information about post-employment compensation, including severance arrangements under our change in control program, is included in the section entitled Potential Payments upon Termination or Change in Control.
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Executive Stock Ownership Requirements
Effective January 1, 2006, the Compensation Committee adopted Common Stock ownership requirements for officers of Southern Company and its subsidiaries that are in a position of Vice President or above. All of the named executive officers are covered by the requirements. The guidelines were implemented to further align the interest of officers and Southern Company’s stockholders by promoting a long-term focus and long-term share ownership.
The types of ownership arrangements counted toward the requirements are shares owned outright, those held in Southern Company-sponsored plans, and Common Stock accounts in the Deferred Compensation Plan and the Supplemental Benefit Plan. One-third of vested Southern Company stock options may be counted, but if so, the ownership target is doubled.
The requirements are expressed as a multiple of base salary as per the table below.
Current officers have until September 30, 2011 to meet the applicable ownership requirement. Newly-elected officers will have five years to meet the applicable ownership requirement.
Impact of Accounting and Tax Treatments on Compensation
None of the compensation paid to the Gulf Power’s employees, including the named executive officers, is subject to the restrictions under Section 162(m) of the Internal Revenue Code of 1986, as amended (Code).
Policy on Recovery of Awards
Southern Company’s 2006 Omnibus Incentive Compensation Plan provides that, if Southern Company or Gulf Power is required to prepare an accounting restatement due to material noncompliance as a result of misconduct, and if an executive knowingly or grossly negligently engaged in or failed to prevent the misconduct or is subject to automatic forfeiture under the Sarbanes-Oxley Act of 2002, the executive will reimburse Gulf Power the amount of any payment in settlement of awards earned or accrued during the 12-month period following the first public issuance or filing that was restated.
Southern Company Policy Regarding Hedging the Economic Risk of Stock Ownership
Southern Company’s policy is that insiders, including outside directors, will not trade in Southern Company options on the options market and will not engage in short sales.
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COMPENSATION COMMITTEE REPORT
The Compensation Committee met with management to review and discuss the CD&A. Based on such review and discussion, the Compensation Committee recommended to the Southern Company Board of Directors that the CD&A be included in Gulf Power’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007. The Southern Company Board of Directors approved that recommendation.
Members of the Compensation Committee:
J. Neal Purcell, Chair
Jon A. Boscia
H. William Habermeyer, Jr.
Donald M. James
SUMMARY COMPENSATION TABLE
The Summary Compensation Table shows the amount and type of compensation received by the Chief Executive Officer, the Chief Financial Officer, and the next four most highly-paid executive officers who served in 2007. Collectively, these officers are referred to as the “named executive officers.”
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Column (d)
The amounts reported in this column for 2007 were relocation incentives that are paid to employees who are promoted and relocate geographically, at the request of the employer. It is a lump sum payment equal to 10% of base salary. Both Ms. Terry and Mr. McCullough relocated in 2007.
Column (e)
No equity-based compensation has been awarded to the named executive officers, or any other employees of Gulf Power, other than Stock Option Awards which are reported in column (f).
Column (f)
This column reports the dollar amounts recognized for financial statement reporting purposes with respect to 2007 in accordance with FASB Statement of Financial Accounting Standards No. 123 (revised 2004) (FAS 123R) disregarding any estimates of forfeitures relating to service-based vesting conditions. See Note 1 to the financial statements of Gulf Power in Item 8 herein for a discussion of the assumptions used in calculating these amounts.
For Messrs. Labrato and Jacob, the amounts shown equal the grant date fair value for the 2007 options granted in 2007, as reported in the Grants of Plan-Based Awards Table because these named executive officers have been retirement eligible for several years and therefore their options will vest in full upon termination. Accordingly, under FAS 123R, the full grant date fair value of their option awards is expensed in the year of grant. However, for Mss. Story, Manuel, and Terry and Mr. McCullough, the amounts reported reflect the amounts expensed in 2007 attributable to the following stock option grants made in 2007 and in prior years because each of these named executive officers was not retirement eligible on the grant dates. Therefore, the grant date fair value for options granted to Mss. Story, Manuel, and Terry and Mr. McCullough is recognized over the shorter period of a) the vesting period of each option or b) the period to the date they become retirement eligible. The grant date fair value for the grant made in 2007 is reported in the Grants of Plan-Based Awards Table.
Column (g)
The amounts in this column are the aggregate of the payouts under the annual incentive program and the performance dividend program attributable to performance periods ending December 31, 2007 that are discussed in detail in the CD&A. The amounts paid under each program to the named executive officers are shown below:
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§ Column (h)
This column reports the aggregate change in the actuarial present value of each named executive officer’s accumulated benefit under the Pension Plan and the supplemental pension plans (collectively, Pension Benefits) during 2006 and 2007. The amount included for 2006 is the difference between the actuarial present values of the Pension Benefits measured as of September 30, 2005 and September 30, 2006; the 2007 amount is the difference in the actuarial present values of the Pension Benefits measured as of September 30, 2006 and September 30, 2007. The Pension Benefits as of each measurement date are based on the named executive officer’s age, pay, and service accruals and the plan provisions applicable as of the measurement date. The actuarial present values as of each measurement date reflect the assumptions Gulf Power selected for Statement of Financial Accounting Standards No. 87, “Employers’ Accounting for Pensions” cost purposes as of that measurement date; however, the named executive officers were assumed to remain employed at Gulf Power until their benefits commence at the pension plans’ stated normal retirement date, generally age 65. As a result, the amounts in column (h) related to Pension Benefits represent the combined impact of several factors-growth in the named executive officer’s Pension Benefits over the measurement year; impact on the total present values of one year shorter discounting period due to the named executive officer being one year closer to normal retirement; impact on the total present values attributable to changes in assumptions from measurement date to measurement date; and impact on the total present values attributable to plan changes between measurement dates.
For more information about the Pension Benefits and the assumptions used to calculate the actuarial present value of accumulated benefits as of September 30, 2007, see the information following the Pension Benefits Table. The key differences between assumptions used for the actuarial present values of accumulated benefits calculations as of September 30, 2006 and September 30, 2007 follow:
The pension plans’ provisions were substantively the same as of September 30, 2005 and September 30, 2006. However, the present values of accumulated Pension Benefits as of September 30, 2007 reflect new provisions regarding the form and timing of payments from the supplemental pension plans. These changes bring those plans into compliance with Section 409A of the Code. The key change was to the form of payment. Instead of providing monthly payments for the lifetime of each named executive officer and his/her spouse, these plans will pay the single sum value of those benefits for an average lifetime in 10 annual installments. Calculations of the present value of accumulated benefits calculations shown prior to September 30, 2007 reflect supplemental pension benefits being paid monthly for the lifetimes of named executive officers and their spouses. The 2007 change in pension value reported in column (h) for each named executive officer is greater than what it otherwise would have been due to the new form of payment. This new form of payment is described more fully in the information following the Pension Benefits Table.
This column also reports above-market earnings on deferred compensation. Above-market earnings are defined by the SEC as any amount above 120% of the applicable federal long-term rate as prescribed under Section 1274(d) of the Code.
Under the Deferred Compensation Plan, eligible employees are permitted to defer up to 50% of their salary and 100% of payments under the annual incentive program or the performance dividend program. The deferred amounts are then treated as if invested in one of two investment options - at the election of the participant. Amounts may be treated as if invested in the Common Stock (Stock Equivalent Account) or the prime interest rate as published in the Wall Street Journal as the base rate on corporate loans posted as of the last business day of each month by at least 75% of the United States’ largest banks (Prime Equivalent Account).
The amounts invested in the Stock Equivalent Account are treated as if dividends are paid and reinvested at the same rate as that paid to Southern Company’s stockholders. That amount is not considered “above-market” as defined by the SEC.
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In 2006 and 2007, the prime interest rate used in the Prime Equivalent Account exceeded 120% of the applicable long-term rate in effect at the measurement point under the SEC’s rules. Therefore, earnings that exceed the amount calculated at that rate are reported here. The range of interest rates under the Prime Equivalent Account was 7.25% to 8.25% in 2006 and 2007 and the applicable long-term rate was 7.14%.
The table below itemizes the amounts reported in this column.
Column (i)
This column reports the following items: perquisites; tax reimbursements by Gulf Power on certain perquisites; Gulf Power’s contributions in 2007 to the Southern Company Employee Savings Plan (ESP), which is a tax-qualified defined contribution plan intended to meet requirements of Section 401(k) of the Code; and contributions in 2007 under the Southern Company Supplemental Benefit Plan (Non-Pension Related) (SBP). The SBP is described more fully in the information following the Nonqualified Deferred Compensation Table.
The amounts reported are itemized below.
Description of Perquisites
Personal Financial Planning is provided for most officers of Gulf Power, including all of the named executive officers. Gulf Power pays for the services of the financial planner on behalf of the officers, up to a maximum amount of $8,700 per year, after the initial year that the benefit is provided. In the initial year, the allowed amount is $15,000. Gulf Power also provides a five-year allowance of $6,000 for estate planning and tax return preparation fees.
Personal Use of Company-Provided Club Memberships. Gulf Power provides club memberships to certain officers, including all of the named executive officers. The memberships are provided for business use; however, personal use is permitted. The amount included reflects the pro-rata portion of the membership fees paid by Gulf Power that are attributable to the named executive officers’ personal use. Direct costs associated with any personal use, such as meals, are paid for or reimbursed by the employee and therefore are not included.
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Relocation Benefits. These benefits are provided to cover the costs associated with geographic relocation.
Personal Use of Corporate-Owned Aircraft. Southern Company owns aircraft that are used to facilitate business travel. All flights on these aircraft must have a business purpose. Also, if seating is available, Southern Company permits a spouse or other family member to accompany an employee on a flight. However, because in such cases the aircraft is being used for a business purpose, there is no incremental cost associated with the spousal travel and no amounts are included for such travel. Any additional expenses incurred that are related to spousal travel are included.
Home Security Systems. Gulf Power pays for the services of third-party providers for the installation, maintenance, and monitoring of the named executive officers’ home security systems.
Other Miscellaneous Perquisites. The amount included reflects the full cost to Gulf Power of providing the following items: personal use of Company-provided tickets for sporting and other entertainment events, and gifts distributed to and activities provided to attendees at Southern Company-sponsored events.
GRANTS OF PLAN-BASED AWARDS MADE IN 2007
The Grants of Plan-Based Awards Table provides information on stock option grants made and goals established for future payouts under Gulf Power’s incentive compensation programs during 2007 by the Compensation Committee. In this table, the annual incentive and the performance dividend payouts are referred to as PPP and PDP, respectively.
Columns (c), (d), and (e)
The amounts reported as PPP reflect the amounts established by the Compensation Committee in early 2007 to be paid for certain levels of performance as of December 31, 2007 under the annual incentive program, Gulf Power’s short-term incentive program. The Compensation Committee assigns each named executive officer a target incentive opportunity, expressed as a percentage of base salary, that is paid for target-level performance under the annual incentive program. The target incentive opportunities established for the named executive officers for 2007
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performance were 60% for Ms. Story, 45% for Mss. Manuel and Terry and Messrs. Labrato and Jacob, and 40% for Mr. McCullough at year-end 2007. Due to changes in job assignments in 2007, target incentive opportunities for Mss. Manuel and Terry and Mr. McCullough were 40%, 40%, and 35%, respectively for a portion of 2007. The payout for threshold performance was set at 0.225 times the target incentive opportunity and the maximum amount payable was set at 2.20 times the target. The amount paid to each named executive officer under the annual incentive program for actual 2007 performance is included in the Non-Equity Incentive Plan Compensation column in the Summary Compensation Table and is itemized in the notes following that table. More information about the annual incentive program, including the applicable performance criteria established by the Compensation Committee, is provided in the CD&A.
Gulf Power also has a long-term incentive program, the performance dividend program, that pays performance-based dividend equivalents based on Southern Company’s total shareholder return (TSR) compared with the TSR of its peer companies over a four-year performance measurement period. The Compensation Committee establishes the level of payout for prescribed levels of performance over the measurement period.
In February 2007, the Compensation Committee established the performance dividend program goal for the four-year performance measurement period beginning on January 1, 2007 and ending on December 31, 2010. The amount earned in 2010 based on the performance measurement for 2007-2010 will be paid following the end of the period. However, no amount is earned and paid unless the Compensation Committee approves the payment at the beginning of the final year of the performance measurement period. Also, nothing is earned unless Southern Company’s earnings are sufficient to fund a Common Stock dividend at the same level as the prior year.
The performance dividend program pays to all option holders a percentage of the Common Stock dividend paid to Southern Company’s stockholders in the last year of the performance measurement period. It can range from approximately five percent for performance above the 10th percentile compared with the performance of the peer companies to 100% of the dividend if Southern Company’s TSR is at or above the 90th percentile. That amount is then paid per option held at the end of the four-year period. The amount, if any, ultimately paid to the option holders, including the named executive officers, at the end of the last year of the 2007-2010 performance measurement period will be based on (1) Southern Company’s TSR compared to that of its peer companies as of December 31, 2010, (2) the actual dividend paid in 2010 to Southern Company’s stockholders, if any, and (3) the number of options held by the named executive officers on December 31, 2010.
The number of options held on December 31, 2010 will be affected by the number of additional options granted to the named executive officers prior to December 31, 2010, if any, and the number of options exercised by the named executive officers prior to December 31, 2010, if any. None of these components necessary to calculate the range of payout under the performance dividend program for the 2007-2010 performance measurement period is known at the time the goal is established.
The amounts reported as PDP in columns (c), (d), and (e) were calculated based on the number of options held by the named executive officers on December 31, 2007, as reported in columns (b) and (c) of the Outstanding Equity Awards at Fiscal Year-End Table and the Common Stock dividend of $1.595 per share paid to Southern Company’s stockholders in 2007. These factors are itemized below.
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More information about the performance dividend program is provided in the CD&A.
Columns (f), (g), and (h)
The stock options vest at the rate of one-third per year, on the anniversary date of the grant. Also, grants fully vest upon termination as a result of death, total disability, or retirement and expire five years after retirement, three years after death or total disability, or their normal expiration date if earlier. Please see Potential Payments Upon Termination or Change In Control for more information about the treatment of stock options under different termination and change in control events.
The Compensation Committee granted these stock options to the named executive officers at its regularly scheduled meeting on February 19, 2007. February 19, 2007 was a holiday (Presidents’ Day) and the New York Stock Exchange, Inc. (NYSE) was closed. Therefore, under the terms of the Omnibus Incentive Compensation Plan, the exercise price was set at the closing price ($36.42 per share) on the last trading day prior to the grant date which was February 16, 2007.
Column (i)
The value of stock options granted in 2007 was derived using the Black-Scholes stock option pricing model. The assumptions used in calculating these amounts are discussed in Note 1 to the financial statements of Gulf Power in Item 8 herein.
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OUTSTANDING EQUITY AWARDS AT 2007 FISCAL YEAR-END
This table provides information pertaining to all outstanding stock options held by the named executive officers as of December 31, 2007.
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Stock options vest one-third per year on the anniversary of the grant date. Options granted from 2001 through 2004, were fully vested as of December 31, 2007. The options granted in 2005, 2006, and 2007 become fully vested as shown below.
Options also fully vest upon death, total disability, or retirement and expire three years following death or total disability or five years following retirement, or on the original expiration date if earlier. Please see Potential Payments Upon Termination or Change In Control for more information about the treatment of stock options under different termination and change in control events.
OPTION EXERCISES AND STOCK VESTED IN 2007
None of the named executive officers were granted Stock Awards. Of the named executive officers, only Mr. McCullough did not exercise options in 2007.
PENSION BENEFITS AT 2007 FISCAL YEAR-END
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The named executive officers earn employer-paid pension benefits from three integrated retirement plans. More information about pension benefits is provided in the CD&A.
The Pension Plan
The Pension Plan is a, tax-qualified, funded plan. It is Southern Company’s primary retirement plan. Generally, all full-time employees participate in this plan after one year of service. Normal retirement benefits become payable when participants both attain age 65 and complete five years of participation. The plan benefit equals the greater of amounts computed using a “1.7% offset formula” and a “1.25% formula,” as described below. Benefits are limited to a statutory maximum.
The 1.7% offset formula amount equals 1.7% of final average pay times years of participation less an offset related to Social Security benefits. The offset equals a service ratio times 50% of the anticipated Social Security benefits in excess of $4,200. The service ratio adjusts the offset for the portion of a full career that a participant has worked. The highest three rates of pay out of a participant’s last 10 calendar years of service are averaged to derive final average pay. The pay considered for this formula is the base rate of pay reduced for any voluntary deferrals. A statutory limit restricts the amount considered each year; the limit for 2007 was $225,000.
The 1.25% formula amount equals 1.25% of final average pay times years of participation. For this formula, the final average pay computation is the same as above, but annual cash incentives paid during each year are added to the base rates of pay.
Early retirement benefits become payable once plan participants have during employment both attained age 50 and completed 10 years of participation. Participants who retire early from active service receive benefits equal to the amounts computed using the same formulas employed at normal retirement. However, a 0.3% reduction applies for each month (3.6% for each year) prior to normal retirement that participants elect to have their benefit payments commence. For example, 64% of the formula benefits are payable starting at age 55. As of December 31, 2007, only Messrs. Labrato and Jacob were eligible to retire immediately.
The Pension Plan’s benefit formulas produce amounts payable monthly over a participant’s post-retirement lifetime. At retirement, plan participants can choose to receive their benefits in one of seven alternative forms of payment. All forms pay benefits monthly over the lifetime of the retiree or the joint lifetimes of the retiree and a spouse. A reduction applies if a retiring participant chooses a payment form other than a single life annuity. The reduction makes the value of the benefits paid in the form chosen comparable to what it would have been if benefits were paid as a single life annuity over the retiree’s life.
Participants vest in the Pension Plan after completing five years of service. All the named executive officers are vested in their Pension Plan benefits. Participants who terminate employment after vesting can elect to have their pension benefits commencing at age 50 if they participated in the Pension Plan for 10 years. If such an election is made, the early retirement reductions that apply are actuarially determined factors and are larger than 0.3% per month.
If a participant dies while actively employed, benefits will be paid to a surviving spouse. A survivor’s benefit equals 45% of the monthly benefit that the participant had earned before his or her death. Payments to a surviving spouse of a participant who could have retired will begin immediately. Payments to a survivor of a participant who was not retirement eligible will begin when the deceased participant would have attained age 50. After commencing, survivor benefits are payable monthly for the remainder of a survivor’s life. Participants who are eligible for early retirement may opt to have an 80% survivor benefit paid if they die; however, there is a charge associated with this election.
If participants become totally disabled, periods that Social Security or employer provided disability income benefits are paid will count as service for benefit calculation purposes. The crediting of this additional service ceases at the point a disabled participant elects to commence retirement payments. Outside of the extra service crediting, the normal plan provisions apply to disabled participants.
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The Southern Company Supplemental Benefit Plan (Pension-Related) (SBP-P)
The SBP-P is an unfunded retirement plan that is not tax-qualified. This plan provides to high-paid employees any benefits that the Pension Plan cannot pay due to statutory pay/benefit limits and voluntary pay deferrals. The SBP-P’s vesting, early retirement, and disability provisions mirror those of the Pension Plan.
The amounts paid by the SBP-P are based on the additional monthly benefit that the Pension Plan would pay if the statutory limits and pay deferrals were ignored. When an SBP-P participant separates from service, vested monthly benefits provided by the benefit formulas are converted into a single sum value. It equals the present value of what would have been paid monthly for an actuarially determined average post-retirement lifetime. The discount rate used in the calculation is based on the 30-year Treasury yields for the September preceding the calendar year of separation, but not more than 6%. Vested participants terminating prior to becoming eligible to retire will be paid their single sum value as of September 1 following the calendar of separation. If the terminating participant is retirement eligible, the single sum value will be paid in 10 annual installments starting shortly after separation. The unpaid balance of a retiree’s single sum will be credited with interest at the prime rate published in The Wall Street Journal. If the separating participant is a “key man” under Section 409A of the Code, the first installment will be delayed for six months after the date of separation.
If an SBP-P participant dies after becoming vested in the Pension Plan, the spouse of the deceased participant will receive the installments the participant would have been paid upon retirement. If a vested participant’s death occurs prior to age 50, the installments will be paid to a survivor as if the participant had survived to age 50.
The Southern Company Supplemental Executive Retirement Plan (SERP)
The SERP also is an unfunded retirement plan that is not tax qualified. This plan provides to high paid employees additional benefits that the Pension Plan and the SBP-P would pay if the 1.7% offset formula calculations reflected a portion of annual cash incentives. To derive the SERP benefits, a final average pay is determined reflecting participants’ base rates of pay and their incentives to the extent they exceed 15% of those base rates (ignoring statutory limits and pay deferrals). This final average pay is used in the 1.7% offset formula to derive a gross benefit. The Pension Plan and the SBP-P benefits are subtracted from the gross benefit to calculate the SERP benefit. The SERP’s early retirement, survivor benefit and disability provisions mirror the SBP-P’s provisions. However, except upon a change in control, SERP benefits do not vest until participants retire, so no benefits are paid if a participant terminates prior to becoming eligible to retire. More information about vesting and payment of SERP benefits following a change in control is included in the section entitled Potential Payments Upon Termination or Change In Control.
The following assumptions were used in the present value calculations:
•
Discount rate - 6.3% as of September 30, 2007
•
Retirement date - Normal retirement age (65 for all named executive officers)
•
Mortality after normal retirement - RP2000 Combined Healthy mortality rate table
•
Mortality, withdrawal, disability and retirement rates prior to normal retirement - None
•
Form of payment for Pension Benefits
•
Percent married at retirement - 80% of males and 70% of females
•
Spouse ages - Wives two years younger than their husbands
•
Incentives earned but unpaid as of the measurement date - 130% of target percentages times base rate of pay for year incentive is earned.
•
Installment determination-5.30% discount rate for single sum calculation and 7.30% prime rate during installment payment period
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For all of the named executive officers, the number of years of credited service is one year less than the number of years of employment.
NONQUALIFIED DEFERRED COMPENSATION AS OF 2007 FISCAL YEAR-END
Southern Company provides the Deferred Compensation Plan (DCP) which is designed to permit participants to defer income as well as certain federal, state, and local taxes until a specified date or their retirement, or other separation from service. Up to 50% of base salary and up to 100% of the annual incentive and performance dividends may be deferred, at the election of eligible employees. All of the named executive officers are eligible to participate in the DCP.
Participants have two options for the deemed investments of the amounts deferred - the Stock Equivalent Account and the Prime Equivalent Account. Under the terms of the DCP, participants are permitted to transfer between investments at any time.
The amounts deferred in the Stock Equivalent Account are treated as if invested at an equivalent rate of return to that of an actual investment in Common Stock, including the crediting of dividend equivalents as such are paid by Southern Company from time to time. It provides participants with an equivalent opportunity for the capital appreciation (or loss) and income held by a Southern Company stockholder. During 2007, the rate of return in the Stock Equivalent Account was 9.83%, which was Southern Company’s TSR for 2007.
Alternatively, participants may elect to have their deferred compensation deemed invested in the Prime Equivalent Account which is treated as if invested at a prime interest rate compounded monthly, as published in the Wall Street Journal as the base rate on corporate loans posted as of the last business day of each month by at least 75% of the United States’ largest banks. The range of interest rates earned on amounts deferred during 2007 in the Prime Equivalent Account was 7.25% to 8.25%.
Column (b)
This column reports the actual amounts of compensation deferred under the DCP by each named executive officer in 2007. The amount of salary deferred by the named executive officers, if any, is included in the Salary column in the Summary Compensation Table. The amount of incentive compensation deferred in 2007 was the amount paid for performance under the annual incentive program and the performance dividend program that were earned as of December 31, 2006 but not payable until the first quarter of 2007. This amount is not reflected in the Summary Compensation Table because that table reports incentive compensation that was earned in 2007, but not payable until early 2008. These deferred amounts may be distributed in a lump sum or in up to 10 annual installments at termination of employment or in a lump sum at a specified date, at the election of the participant.
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Column (c)
This column reflects contributions under the SBP. Under the Code, employer matching contributions are prohibited under the ESP on employee contributions above stated limits in the ESP, and, if applicable, above legal limits set forth in the Code. The SBP is a nonqualified deferred compensation plan under which contributions are made that are prohibited from being made in the ESP. The contributions are treated as if invested in Common Stock and are payable in cash upon termination of employment in a lump sum or in up to 20 annual installments, at the election of the participant. The amounts reported in this column were also reported in the All Other Compensation column in the Summary Compensation Table.
Column (d)
This column reports earnings on both compensation the named executive officers elected to defer and earnings on employer contributions under the SBP. See the notes to column (h) of the Summary Compensation Table for a discussion of amounts of nonqualified deferred compensation earnings included in the Summary Compensation Table.
Column (f)
This column includes amounts that were deferred under the DCP and contributions under the SBP in prior years and reported in prior years’ Information Statements or Annual Reports on Form 10-K. The chart below shows the amounts reported in prior years’ Information Statements or Annual Reports on Form 10-K.
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL
This section describes and estimates payments that could be made to the named executive officers under different termination and change in control events. The estimated payments would be made under the terms of Southern Company’s compensation and benefits programs or the change in control severance program. All of the named executive officers are participants in Southern Company’s change in control severance plan for officers. (As described in the CD&A, all employees not part of a collective bargaining unit are participants in a change in control severance plan.) The amount of potential payments is calculated as if the triggering events occurred as of December 31, 2007 and assumes that the price of Common Stock is the closing market price as of December 31, 2007.
Description of Termination and Change in Control Events
The following charts list different types of termination and change in control events that can affect the treatment of payments under the compensation and benefit programs. These events also affect payments to the named executive officers under their change in control severance agreements. No payments are made under the severance
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agreements unless, within two years of the change in control, the named executive officer is involuntarily terminated or he or she voluntarily terminates for Good Reason. (See the description of Good Reason below.)
Traditional Termination Events
•
Retirement or Retirement Eligible - Termination of a named executive officer who is at least 50 years old and has at least 10 years of credited service.
•
Resignation - Voluntary termination of a named executive officer who is not retirement eligible.
•
Lay Off - Involuntary termination of a named executive officer not for cause, who is not retirement eligible.
•
Involuntary Termination - Involuntary termination of a named executive officer for cause. Cause includes individual performance below minimum performance standards and misconduct, such as violation of Gulf Power’s Drug and Alcohol Policy.
•
Death or Disability - Termination of a named executive officer due to death or disability.
Change in Control-Related Events
At the Southern Company or Gulf Power level:
•
Southern Company Change in Control I - Acquisition by another entity of 20% or more of Common Stock, or following a merger with another entity Southern Company’s stockholders own 65% or less of the entity surviving the merger.
•
Southern Company Change in Control II - Acquisition by another entity of 35% or more of Common Stock, or following a merger with another entity Gulf Power’s stockholders own less than 50% of Gulf Power surviving the merger.
•
Southern Company Termination - A merger or other event and Southern Company is not the surviving company or the Common Stock is no longer publicly traded.
•
Gulf Power Change in Control - Acquisition by another entity, other than another subsidiary of Southern Company, of 50% or more of the stock of Gulf Power, a merger with another entity and Gulf Power is not the surviving company, or the sale of substantially all the assets of Gulf Power.
At the employee level:
•
Involuntary Change in Control Termination or Voluntary Change in Control Termination for Good Reason - Employment is terminated within two years of a change in control, other than for cause, or the employee voluntarily terminates for Good Reason. Good Reason for voluntary termination within two years of a change in control is generally satisfied when there is a material reduction in salary, incentive compensation opportunity or benefits, relocation of over 50 miles, or a diminution in duties and responsibilities.
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The following chart describes the treatment of different pay and benefit elements in connection with the Traditional Termination Events described above.
Lay Off
Retirement/
(Involuntary
Involuntary
Retirement
Termination Not
Termination
Program
Eligible
For Cause)
Resignation
Death or Disability
(For Cause)
Pension Benefits Plans
Benefits payable as described in the notes following the Pension Benefits Table.
Benefits payable as described in the notes following the Pension Benefits Table.
Same as Lay Off.
Benefits payable as described in the notes following the Pension Benefits Table.
Same as for retirement and resignation, as the case may be.
Annual Incentive Program
Pro-rated if terminate before 12/31.
Pro-rated if terminate before 12/31.
Forfeit.
Pro-rated if terminate before 12/31.
Forfeit.
Performance Dividend
Program
Paid year of retirement plus two additional years.
Forfeit.
Forfeit.
Payable until options expire or exercised.
Forfeit.
Stock Options
Vest; expire earlier of original expiration date or five years.
Vested options expire in 90 days; unvested are forfeited.
Vested options expire in 90 days; unvested are forfeited.
Vest; expire earlier of original expiration or three years.
Forfeit.
Financial Planning Perquisite
Continues for one year.
Terminates.
Terminates.
Continues for one year.
Terminates.
Deferred Compensation Plan
Payable per prior elections (lump sum or up to 10 annual installments).
Same as Retirement.
Same as Retirement.
Payable to beneficiary or disabled participant per prior elections; amounts deferred prior to 2005 can be paid as a lump sum per plan administration committee’s discretion.
Same as Retirement.
Supplemental Benefit Plan -
non-pension related
Payable per prior elections (lump sum or up to 20 annual installments).
Same as Retirement.
Same as Retirement.
Same as the Deferred Compensation Plan.
Same as Retirement.
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The chart below describes the treatment of payments under pay and benefit programs under different change in control events, except the Pension Plan (Change in Control Chart). The Pension Plan is not affected by change in control events.
Involuntary Change
in Control-Related
Termination or
Southern Company
Voluntary Change in
Termination or Gulf
Control-Related
Southern Company
Southern Company
Power Change in
Termination for
Program
Change in Control I
Change in Control II
Control
Good Reason
Nonqualified
Pension Benefits
All SERP-related benefits vest if participant vested in tax-qualified pension benefits; otherwise, no impact.
Benefits vest for all participants and single sum value of benefits earned to the change in control date paid following termination or retirement.
Same as Southern Company Change in Control II.
Based on type of change in control event.
Annual Incentive
No plan termination is paid at greater of target or actual performance. If plan terminated within two years of change in control, pro-rated at target performance level.
Same as Southern Company Change in Control I.
Pro-rated at target performance level.
If not otherwise eligible for payment, if annual incentive still in effect, pro-rated at target performance level.
Performance Dividend
No plan termination is paid at greater of target or actual performance. If plan terminated within two years of change in control, pro-rated at greater of target or actual performance level.
Same as Southern Company Change in Control I.
Pro-rated at greater of actual or target performance level.
If not otherwise eligible for payment, if the performance dividend program is still in effect, greater of actual or target performance level for year of severance only.
Stock Options
Not affected by change in control events.
Not affected by change in control events.
Vest and convert to surviving company’s securities; if cannot convert, pay spread in cash.
Vest.
DCP
Not affected by change in control events.
Not affected by change in control events.
Not affected by change in control events.
Not affected by change in control events.
SBP
Not affected by change in control events.
Not affected by change in control events.
Not affected by change in control events.
Not affected by change in control events.
III-34
Involuntary Change
in Control-Related
Termination or
Southern Company
Voluntary Change in
Termination or Gulf
Control-Related
Southern Company
Southern Company
Power Change in
Termination for
Program
Change in Control I
Change in Control II
Control
Good Reason
Severance Benefits
Not applicable.
Not applicable.
Not applicable.
Two or three times base salary plus target annual incentive plus tax gross up for certain named executive officers if severance amounts exceed Section 280G of the Code “excess parachute payment” by 10% or more.
Health Benefits
Not applicable.
Not applicable.
Not applicable.
Up to five years participation in group health plan plus payment of two or three years’ premium amounts.
Outplacement
Services
Not applicable.
Not applicable.
Not applicable.
Six months.
Potential Payments
This section describes and estimates payments that would become payable to the named executive officers upon a termination or change in control as of December 31, 2007.
Pension Benefits
The amounts that would have become payable to the named executive officers if the Traditional Termination Events occurred as of December 31, 2007 under the Pension Plan, the SBP-P, and the SERP are itemized in the chart below. The amounts shown under the column “Retirement” are amounts that would have become payable to the named executive officers that were retirement eligible on December 31, 2007 and are the monthly Pension Plan benefits and the first of 10 annual installments from the SBP-P and the SERP. The amounts shown under the column “Resignation or Involuntary Termination” are the amounts that would have become payable to the named executive officers who were not retirement eligible on December 31, 2007 and are the monthly Pension Plan benefits that would become payable as of the earliest possible date under the Pension Plan and the single sum value of benefits earned up to the termination date under the SBP-P, paid as a single payment rather than in 10 annual installments. Benefits under the SERP would be forfeited. The amounts shown that are payable to a spouse in the event of the death of the named executive officer are the monthly amounts payable to a spouse under the Pension Plan and the first of 10 annual installments from the SBP-P and the SERP. The amounts in this chart are very different from the pension values shown in the Summary Compensation Table and the Pension Benefits Table. Those tables show the present values of all the benefits amounts anticipated to be paid over the lifetimes of the named executive officers and their spouses. Those plans are described in the notes following the Pension Benefits Table. Of the named executive officers, only Messrs. Labrato and Jacob were retirement eligible on December 31, 2007.
III-35
As described in the Change in Control Chart, the only change in the form of payment, acceleration or enhancement of the pension benefits is that the single sum value of benefits earned up to the change in control date under the SBP-P and the SERP could be paid as a single payment rather than in 10 annual installments. Also, the SERP benefits vest for participants who are not retirement eligible upon a change in control. Estimates of the single sum payment that would have been made to the named executive officers, assuming termination as of December 31, 2007 following a change in control event, other than a Southern Company Change in Control I (which does not impact how pension benefits are paid), are itemized below. These amounts would be paid instead of the benefits shown in the Traditional Termination Events table above; they are not paid in addition to those amounts.
The pension benefit amounts in the tables above were calculated as of December 31, 2007 assuming payments would begin as soon as possible under the terms of the plans. Accordingly, appropriate early retirement reductions were applied. Any unpaid incentives were assumed to be paid at 1.35 times the target level. Pension Plan benefits were calculated assuming named executive officers chose a single life annuity form of payment, because that results in the greatest monthly benefit. The single sum values of the SBP-P and the SERP benefits were based on a 4.85% discount rate as prescribed by the terms of the plan for those who separated from service in 2007.
III-36
Annual Incentive
Because this section assumes that a termination or change in control event occurred on December 31, 2007, there is no amount that would be payable other than what was reported and described in the Summary Compensation Table because actual performance in 2007 exceeded target performance.
Performance Dividends
Because the assumed termination date is December 31, 2007, there is no additional amount that would be payable other than what was reported in the Summary Compensation Table under the Traditional Termination Events. As described in the Traditional Termination Events chart, there is some continuation of benefits under the performance dividend program for retirees.
However, under the Change in Control-Related Events, performance dividends are payable at the greater of target performance or actual performance. For the 2004-2007 performance period, actual performance was less than target performance. The table below estimates the additional amount that would have been payable under the performance dividend program if a change in control occurred as of December 31, 2007.
Stock Options
Stock Options would be treated as described in the Termination and Change in Control charts above. Under a Southern Company Termination, all stock options vest. In addition, if there is an Involuntary Change in Control Termination or Voluntary Change in Control Termination for Good Reason, stock options vest. There is no payment associated with stock options unless there is a Southern Company Termination and the participants’ stock options cannot be converted into surviving company stock options. In that event, the excess of the exercise price and the closing price of the Common Stock on December 31, 2007 would be paid in cash for all stock options held by the named executive officers. The chart below shows the number of stock options for which vesting would be accelerated under a Southern Company Termination and the amount that would be payable under a Southern Company Termination if there were no conversion to the surviving company’s stock options.
III-37
DCP and SBP
The aggregate balances reported in the Nonqualified Deferred Compensation Table would be payable to the named executive officers as described in the Traditional Termination and Change in Control-Related Events charts above. There is no enhancement or acceleration of payments under these plans associated with termination or change in control events, other than the lump-sum payment opportunity described in the above charts. The lump sums that would be payable are those that are reported in the Nonqualified Deferred Compensation Table.
Health Benefits
Messrs. Labrato and Jacob are retirement eligible and health care benefits are provided to retirees, and there is no incremental payment associated with the termination or change in control events. At the end of 2007, Mss. Story, Manuel and Terry and Mr. McCullough were not retirement eligible and thus health care benefits would not become available until each reaches age 50, except in the case of a change in control-related termination, as described in the Change in Control-Related Events chart. The estimated cost of providing three years of group health insurance premiums for Ms. Story is $14,228 and two years of group health insurance premiums for Ms. Manuel is $26,682; Ms. Terry is $9,071 and Mr. McCullough is $27,257.
Financial Planning Perquisite
Since Messrs. Labrato and Jacob are retirement eligible, an additional year of the Financial Planning perquisite, which is set at a maximum of $8,700 per year, is provided after retirement or will be provided after retirement. Mss. Story, Manuel, and Terry and Mr. McCullough are not retirement eligible.
There are no other perquisites provided to the named executive officers under any of the traditional termination or change in control-related events.
Severance Benefits
The named executive officers are participants in a change in control severance plan. In addition to the treatment of Health Benefits, the annual incentive program, and the performance dividend program described above, the named executive officers are entitled to a severance benefit, including outplacement services, if within two years of a change in control, they an involuntarily terminated, not for Cause, or they voluntarily terminate for Good Reason. The severance benefits are not paid unless the named executive officer releases Gulf Power from any claims he may have against Gulf Power.
The estimated cost of providing the six months of outplacement services is $6,000 per named executive officer. The severance payment is three times the base salary and target payout under the annual incentive program for Ms. Story and two times the base salary and target payout under the annual incentive program for the other named executive officers. If any portion of the severance payment is an “excess parachute payment” as defined under Section 280G of the Code, Gulf Power will pay the named executive officer an additional amount to cover the taxes that would be due on the excess parachute payment - a “tax gross-up.” However, that additional amount will not be paid unless the severance amount plus all other amounts that are considered parachute payments under the Code exceed 110% of the severance payment.
III-38
The table below estimates the severance payments that would be made to the named executive officers if they were terminated as of December 31, 2007 in connection with a change in control. There is no estimated tax gross-up included for any of the named executive officers because their respective estimated severance amounts payable are below the amounts considered excess parachute payments under the Code.
DIRECTOR COMPENSATION
Only non-employee directors of Gulf Power are compensated for service on the board of directors. The pay components for non-employee directors are:
Annual retainers:
Equity grants:
Meeting fees:
(1) Equity grants may be deferred at the director’s election.
DIRECTOR DEFERRED COMPENSATION PLAN
If deferred, all quarterly equity grants are required to be deferred in the Deferred Compensation Plan For Directors of Gulf Power Company (Director Deferred Compensation Plan) and are invested in Common Stock units which earn dividends as if invested in Common Stock. Earnings are reinvested in additional stock units. Upon leaving the board, distributions are made in shares of Common Stock.
In addition, directors may elect to defer up to 100% of their remaining compensation in the Director Deferred Compensation Plan until membership on the board ends. Deferred compensation may be invested as follows, at the director’s election:
•
in Common Stock units which earn dividends as if invested in Common Stock and are distributed in shares of Common Stock upon leaving the board
•
in Common Stock units which earn dividends as if invested in Common Stock and are distributed in cash upon leaving the board
•
at prime interest which is paid in cash upon leaving the board
III-39
All investments and earnings in the Director Deferred Compensation Plan are fully vested and, at the election of the director, may be distributed in a lump sum payment or in up to 10 annual distributions after leaving the board.
DIRECTOR COMPENSATION TABLE
The following table reports all compensation to Gulf Power’s non-employee directors during 2007, including amounts deferred in the Director Deferred Compensation Plan. Non-employee directors do not receive Non-Equity Incentive Plan Compensation, and there is no pension plan for non-employee directors.
(1)
Includes amounts voluntarily deferred in the Director Deferred Compensation Plan.
(2)
Includes fair market value of equity grants on grant dates. All such stock awards are vested immediately upon grant.
(3)
Above-market earnings on amounts invested in the Director Deferred Compensation Plan. Above-market earnings are defined by the SEC as any amount above 120% of the applicable federal long-term rate as prescribed under Section 1274(d) of the Code.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
The Compensation Committee is made up of non-employee directors of Southern Company who have never served as executive officers of Southern Company or Gulf Power. During 2007, none of Southern Company’s or Gulf Power’s executive officers served on the board of directors of any entities whose directors or officers serve on the Compensation Committee.
III-40
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Security Ownership of Certain Beneficial Owners. Southern Company is the beneficial owner of 100% of the outstanding common stock of Gulf Power.
Security Ownership of Management. The following tables show the number of shares of Southern Company common stock owned by the directors, nominees, and executive officers as of December 31, 2007. It is based on information furnished by the directors, nominees, and executive officers. The shares owned by all directors, nominees, and executive officers as a group constitute less than one percent of the total number of shares outstanding on December 31, 2007.
(1)
“Beneficial ownership” means the sole or shared power to vote, or to direct the voting of, a security and/or investment power with respect to a security or any combination thereof.
(2)
Indicates the number of deferred stock units held under the Director Deferred Compensation Plan.
(3)
Indicates shares of Common Stock that certain executive officers have the right to acquire within 60 days. Shares indicated are included in the Shares Beneficially Owned column.
Changes in Control. Southern Company and Gulf Power know of no arrangements which may at a subsequent date result in any change in control.
III-41
Equity Compensation Plan Information
The following table provides information as of December 31, 2007 concerning shares of Southern Company’s common stock authorized for issuance under Southern Company’s existing non-qualified equity compensation plans.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
Transactions with Related Persons.
None.
Review, Approval or Ratification of Transactions with Related Persons.
Gulf Power does not have a written policy pertaining solely to the approval or ratification of “related party transactions.” Southern Company has a Code of Ethics as well as a Contract Guidance Manual and other formal written procurement policies and procedures that guide the purchase of goods and services, including requiring competitive bids for most transactions above $10,000 or approval based on documented business needs for sole sourcing arrangements.
III-42
Promoters and Certain Control Persons.
None.
Director Independence.
The board of directors of Gulf Power consists of five independent non-employee directors (Messrs. C. LeDon Anchors, William C. Cramer, Jr., Fred C. Donovan, Sr., William A. Pullum, and Winston E. Scott) and Ms. Story, the president and chief executive officer of Gulf Power.
Southern Company owns all of Gulf Power’s outstanding common stock, which represents a substantial majority of the overall voting power of Gulf Power’s equity securities, and Gulf Power has listed only debt securities on the NYSE. Accordingly, under the rules of the NYSE, Gulf Power is exempt from most of the NYSE’s listing standards relating to corporate governance, including requirements relating to certain board committees. Gulf Power has voluntarily complied with certain of the NYSE’s listing standards relating to corporate governance where such compliance was deemed to be in the best interests of Gulf Power’s shareholders.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following represents the fees billed to Gulf Power and Southern Power for the last two fiscal years by Deloitte & Touche LLP, each company’s principal public accountant for 2007 and 2006:
(1)
Includes services performed in connection with financing transactions.
(2)
Includes other non-statutory audit services and accounting consultations.
The Southern Company Audit Committee (on behalf of Southern Company and its subsidiaries) adopted a Policy of Engagement of the Independent Auditor for Audit and Non-Audit Services that includes requirements for such Audit Committee to pre-approve audit and non-audit services provided by Deloitte & Touche LLP. All of the audit services provided by Deloitte & Touche LLP in fiscal years 2007 and 2006 (described in the footnotes to the table above) and related fees were approved in advance by the Southern Company Audit Committee.
III-43
PART IV
Item 15.
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)
The following documents are filed as a part of this report on Form 10-K:
(1)
Financial Statements:
Management’s Report on Internal Control Over Financial Reporting for Southern Company and Subsidiary Companies is listed under Item 8 herein.
Management’s Report on Internal Control Over Financial Reporting for Alabama Power is listed under Item 8 herein.
Management’s Report on Internal Control Over Financial Reporting for Georgia Power is listed under Item 8 herein.
Management’s Report on Internal Control Over Financial Reporting for Gulf Power is listed under Item 8 herein.
Management’s Report on Internal Control Over Financial Reporting for Mississippi Power is listed under Item 8 herein.
Management’s Report on Internal Control Over Financial Reporting for Southern Power and Subsidiary Companies is listed under Item 8 herein.
Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting for Southern Company and Subsidiary Companies is listed under Item 8 herein.
Reports of Independent Registered Public Accounting Firm on the financial statements for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power and Subsidiary Companies are listed under Item 8 herein.
The financial statements filed as a part of this report for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power and Subsidiary Companies are listed under Item 8 herein.
(2)
Financial Statement Schedules:
Reports of Independent Registered Public Accounting Firm as to Schedules for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power and Subsidiary Companies are included herein on pages IV-8, IV-9, IV-10, IV-11, IV-12, and IV-13.
Financial Statement Schedules for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power and Subsidiary Companies are listed in the Index to the Financial Statement Schedules at page S-1.
(3)
Exhibits:
Exhibits for Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power are listed in the Exhibit Index at page E-1.
IV-1
THE SOUTHERN COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
David M. Ratcliffe
Chairman, President,
Chief Executive Officer, and Director
(Principal Executive Officer)
W. Paul Bowers
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
W. Ron Hinson
Comptroller and Chief Accounting Officer
(Principal Accounting Officer)
By: /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: February 25, 2008
IV-2
ALABAMA POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
ALABAMA POWER COMPANY
By: Charles D. McCrary
President and Chief Executive Officer
By: /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: February 25, 2008
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Charles D. McCrary
President, Chief Executive Officer, and Director
(Principal Executive Officer)
Art P. Beattie
Executive Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)
Philip C. Raymond
Vice President and Comptroller
(Principal Accounting Officer)
By:
/s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: February 25, 2008
IV-3
GEORGIA POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
Date: February 25, 2008
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Michael D. Garrett
President, Chief Executive Officer, and Director
(Principal Executive Officer)
Cliff S. Thrasher
Executive Vice President, Chief Financial Officer,
and Treasurer
(Principal Financial Officer)
Ann P. Daiss
Vice President, Comptroller, and Chief Accounting Officer
(Principal Accounting Officer)
Directors:
Robert L. Brown, Jr.
D. Gary Thompson
Ronald D. Brown
Richard W. Ussery
Anna R. Cablik
William Jerry Vereen
David M. Ratcliffe
E. Jenner Wood, III
Jimmy C. Tallent
By: /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: February 25, 2008
IV-4
GULF POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
Date: February 25, 2008
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Susan N. Story
President, Chief Executive Officer, and Director
(Principal Executive Officer)
Ronnie R. Labrato
Vice President and Chief Financial Officer
(Principal Financial Officer)
Constance J. Erickson
Comptroller
(Principal Accounting Officer)
Directors:
C. LeDon Anchors
William A. Pullum
William C. Cramer, Jr.
Winston E. Scott
Fred C. Donovan, Sr.
By: /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: February 25, 2008
IV-5
MISSISSIPPI POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
Date: February 25, 2008
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Anthony J. Topazi
President, Chief Executive Officer, and Director
(Principal Executive Officer)
Frances V. Turnage
Vice President, Treasurer, and
Chief Financial Officer
(Principal Financial Officer)
Moses H. Feagin
Comptroller
(Principal Accounting Officer)
Directors:
Roy Anderson, III
Christine L. Pickering
Tommy E. Dulaney
George A. Schloegel
Robert C. Khayat
Philip J. Terrell
Aubrey B. Patterson, Jr.
By: /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: February 25, 2008
IV-6
SOUTHERN POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
Date: February 25, 2008
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Ronnie L. Bates
President, Chief Executive Officer, and Director
(Principal Executive Officer)
Michael W. Southern
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
Laura I. Patterson
Comptroller
(Principal Accounting Officer)
Directors:
William Paul Bowers
G. Edison Holland, Jr.
Thomas A. Fanning
David M. Ratcliffe
By: /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: February 25, 2008
IV-7
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Southern Company
We have audited the consolidated financial statements of Southern Company and Subsidiaries (the “Company”) as of December 31, 2007 and 2006, and for each of the three years in the period ended December 31, 2007, and the Company’s internal control over financial reporting as of December 31, 2007 and have issued our reports thereon dated February 25, 2008 (which report on the consolidated financial statements expresses an unqualified opinion and includes an explanatory paragraph concerning a change in method of accounting for uncertainty in income taxes and a change in method of accounting for the impact of changes in the timing of income tax cash flows generated by leveraged leases in 2007 and a change in method of accounting for the funded status of defined benefit and other postretirement plans in 2006); such consolidated financial statements and reports are included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedule of the Company (page S-2) listed in the accompanying index at Item 15. This consolidated financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 25, 2008
IV-8
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Alabama Power Company
We have audited the financial statements of Alabama Power Company (the “Company”) as of December 31, 2007 and 2006, and for each of the three years in the period ended December 31, 2007, and have issued our report thereon dated February 25, 2008 (which report expresses an unqualified opinion and includes an explanatory paragraph concerning a change in method of accounting for the funded status of defined benefit and other postretirement plans in 2006); such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company (page S-3) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Birmingham, Alabama
February 25, 2008
IV-9
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Georgia Power Company
We have audited the financial statements of Georgia Power Company (the “Company”) as of December 31, 2007 and 2006, and for each of the three years in the period ended December 31, 2007, and have issued our report thereon dated February 25, 2008 (which report expresses an unqualified opinion and includes an explanatory paragraph concerning a change in method of accounting for uncertainty in income taxes in 2007 and a change in method of accounting for the funded status of defined benefit and other postretirement plans in 2006); such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company (page S-4) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 25, 2008
IV-10
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Gulf Power Company
We have audited the financial statements of Gulf Power Company (the “Company”) as of December 31, 2007 and 2006, and for each of the three years in the period ended December 31, 2007, and have issued our report thereon dated February 25, 2008 (which report expresses an unqualified opinion and includes an explanatory paragraph concerning a change in method of accounting for the funded status of defined benefit and other postretirement plans in 2006); such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company (page S-5) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 25, 2008
IV-11
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Mississippi Power Company
We have audited the financial statements of Mississippi Power Company (the “Company”) as of December 31, 2007 and 2006, and for each of the three years in the period ended December 31, 2007, and have issued our report thereon dated February 25, 2008 (which report expresses an unqualified opinion and includes an explanatory paragraph concerning a change in method of accounting for the funded status of defined benefit and other postretirement plans in 2006); such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company (page S-6) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 25, 2008
IV-12
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Southern Power Company
We have audited the consolidated financial statements of Southern Power Company and Subsidiary Companies (the “Company”) as of December 31, 2007 and 2006, and for each of the three years in the period ended December 31, 2007, and have issued our report thereon dated February 25, 2008; such consolidated financial statements and report are included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedule of the Company (page S-7) listed in the accompanying index at Item 15. This consolidated financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 25, 2008
IV-13
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedules I through V not listed above are omitted as not applicable or not required. Columns omitted from schedules filed have been omitted because the information is not applicable or not required.
S-1
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006, AND 2005
(Stated in Thousands of Dollars)
(a)
Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
(b)
See Note 5 to the financial statements of Southern Company in Item 8 herein.
S-2
ALABAMA POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006, AND 2005
(Stated in Thousands of Dollars)
Note:
Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-3
GEORGIA POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006, AND 2005
(Stated in Thousands of Dollars)
(a)
Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
(b)
See Note 5 to the financial statements of Georgia Power in Item 8 herein.
S-4
GULF POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006, AND 2005
(Stated in Thousands of Dollars)
Note:
Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-5
MISSISSIPPI POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006, AND 2005
(Stated in Thousands of Dollars)
Note:
Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-6
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006, AND 2005
(Stated in Thousands of Dollars)
Note:
Represents write-off of accounts receivable considered to be uncollectible, less recoveries of amounts previously written off.
S-7
EXHIBIT INDEX
The following exhibits indicated by an asterisk (*) preceding the exhibit number are filed herewith. The balance of the exhibits has heretofore been filed with the SEC as the exhibits and in the file numbers indicated and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements required to be identified as such by Item 15 of Form 10-K.
(3) Articles of Incorporation and By-Laws
Southern Company
Alabama Power
Georgia Power
E-1
Gulf Power
Mississippi Power
Southern Power
(4) Instruments Describing Rights of Security Holders, Including Indentures
Southern Company
E-2
Alabama Power
E-3
Georgia Power
E-4
Gulf Power
Mississippi Power
Southern Power
(10) Material Contracts
Southern Company
E-5
E-6
Alabama Power
E-7
E-8
E-9
E-10
E-11
E-12
Southern Power
E-13
E-14
E-15
E-16
E-17