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 the outstanding common stock of Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric, each of which is an operating public utility company. The retail operating companies supply electric service in the states of Alabama, Georgia, Florida, Mississippi and Georgia, respectively. More particular information relating to each of the retail 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 had a 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.
Gulf Power is a corporation which was organized under the laws of the State of Maine on November 2, 1925, and admitted to do business in Florida on January 15, 1926, in Mississippi on October 25, 1976, and in Georgia on November 20, 1984.
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.
Savannah Electric is a corporation existing under the laws of the State of Georgia; its charter was granted by the Secretary of State on August 5, 1921.
In addition, Southern Company owns all of the common stock of Southern Power, which is also an operating public utility company. Southern Power constructs, owns and manages Southern Company's competitive 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 admitted to do business in Alabama, Florida and Georgia on January 10, 2001 and in Mississippi on January 30, 2001.
Southern Company also owns all the outstanding common stock of Southern LINC, Southern Company GAS, Southern Nuclear, SCS, Southern Telecom, Southern Holdings and other direct and indirect subsidiaries. Southern LINC provides digital wireless communications services to Southern Company's retail operating companies and also markets these services to the public within the Southeast. Southern Company GAS, which began operation in August 2002, is a competitive retail natural gas marketer serving communities in Georgia. Southern Nuclear 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 Telecom provides wholesale fiber optic solutions to telecommunication providers in the Southeastern United States. Southern Holdings is an intermediate holding subsidiary for Southern Company's investments in leveraged leases and synthetic fuel products and an energy services business.
Alabama Power and Georgia Power each own 50% of the outstanding common stock of SEGCO. SEGCO owns electric generating units with an aggregate capacity of 1,019,680 kilowatts at Plant Gaston on the Coosa River near Wilsonville, Alabama, and 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 transmission line system.
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Reference is made to Note 10 to the financial statements of Southern Company in Item 8 herein for additional information regarding Southern Company's segment and related information.
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, 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 http://www.southerncompany.com.
The SOUTHERN System
Retail Operating Companies
The transmission facilities of each of the retail 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 retail operating companies and SEGCO by means of heavy-duty high voltage lines. (For information on Georgia Power's integrated transmission system, see Item 1 - BUSINESS - "Territory Served by the Utilities" 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 retail operating companies have entered into voluntary reliability agreements with the subsidiaries of Entergy Corporation, Florida Electric Power Coordinating Group and TVA and with Carolina Power & Light Company, Duke Energy Corporation, 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 retail 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 retail operating companies are represented on the National Electric Reliability Council.
An intra-system interchange agreement provides for coordinating operations of the power producing facilities of the retail 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 retail operating companies and Southern Power to provide the most economical sources of power consistent with good operation. The resulting benefits and savings are apportioned among each of the companies.
SCS has contracted with Southern Company, each retail operating company, Southern Power, Southern Nuclear, SEGCO and other subsidiaries 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, Southern Company GAS, Southern LINC and Southern Telecom have also secured from the retail operating companies certain services which are furnished at cost.
Southern Nuclear has contracts with Alabama Power to operate Plant Farley and with Georgia Power to operate Plants Hatch and Vogtle. See Item 1 - BUSINESS - - "Regulation - Atomic Energy Act of 1954" herein.
Southern Power
Southern Power is an electric wholesale generation subsidiary with market-based rates. Southern Power constructs, 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 retail operating companies (under PPAs approved by the respective PSCs). 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 risk by making such risks the responsibility of the counterparties
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to the PPAs. However, Southern Power's overall profit will depend on the parameters of the wholesale market and its efficient operation of its wholesale generating assets. By the end of 2005, Southern Power plans to have approximately 6,000 megawatts of available generating capacity in commercial operation. At December 31, 2003, Southern Power had approximately 4,800 megawatts of generating capacity in commercial operation.
Other Business
In June 2002, Southern Company formed a wholly-owned subsidiary, Southern Company GAS. Southern Company GAS operates as a retail gas marketer in the State of Georgia. Southern Company GAS completed its acquisition out of bankruptcy from The New Power Company (New Power) and began operations in July 2002. Southern Company GAS also purchased proprietary risk management software and hardware systems, natural gas inventory and accounts receivable from New Power. The total purchase price was approximately $60 million. Southern Company GAS has a 13.5% market share as of December 31, 2003.
Southern Holdings is an intermediate holding subsidiary for Southern Company's investments in leveraged leases and synthetic fuel products, in addition to Southern Company Energy Solutions LLC (SCES LLC), which provides energy services.
In 1996, Southern LINC began serving Southern Company's retail operating companies and marketing its services to non-affiliates within the Southeast. Its system covers approximately 127,000 square miles and combines the functions of two-way radio dispatch, cellular phone, short text and numeric messaging and wireless internet access and data transfer.
These continuing 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.
In 1999, MESH, a subsidiary of Southern Company, filed a petition for Chapter 11 bankruptcy relief in the U.S. Bankruptcy Court. In 2001, MESH filed an amended plan of reorganization, which the U. S. Bankruptcy Court confirmed in September 2003. The plan became effective in late 2003, and Southern Company's equity interest in MESH, which had been written off entirely prior to 2001, was extinguished. Reference is made to Item 3 - "Legal Proceedings" and Note 3 to the financial statements of Southern Company in Item 8 herein under the heading "Mirant Related Matters - Mobile Energy Services' Petition for Bankruptcy" for additional information relating to this matter.
Mirant Corporation
In April 2001, the spin off of Mirant was completed. As a result of the spin off, Southern Company's financial statements and related information reflect Mirant as discontinued operations. Reference is made to Note 3 to the financial statements of Southern Company in Item 8 herein under the heading "Mirant Related Matters" for additional information regarding Mirant.
Risk Factors
In addition to the other information in this Form 10-K 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. Some or all of these factors may apply to Southern Company and/or its subsidiaries.
Risks Related to the Energy Industry
Southern Company is 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.
Southern Company is 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,
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hydroelectric and nuclear generating facilities. For example, the rates charged to wholesale customers by the retail operating companies and by Southern Power must be approved by the FERC. In addition, the respective state PSCs must approve the retail operating companies' rates for retail customers. Southern Company believes the necessary permits, approvals and certificates have been obtained for its existing operations and that its business is conducted in accordance with applicable laws; however, Southern Company is unable to predict the impact on its operating results from future regulatory activities of these agencies.
Southern Company is also subject to regulation by the SEC under the Holding Company Act. The rules and regulations promulgated under the Holding Company Act impose a number of restrictions on the operations of registered utility holding companies and their subsidiaries. These restrictions include a requirement that, subject to a number of exceptions, the SEC approve in advance securities issuances, acquisitions and dispositions of utility assets or of securities of utility companies, and acquisitions of other businesses. The Holding Company Act also generally limits the operations of a registered holding company to a single integrated public utility system, plus additional energy-related businesses. The Holding Company Act requires that transactions between affiliated companies in a registered holding company system be performed at cost, with limited exceptions.
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 Southern Company's operating environment and may result in substantial costs to Southern Company.
General Risks Related to Operation of Southern Company's Utility Subsidiaries
The regional power market in which Southern Company and its subsidiaries compete has changing transmission regulatory structures, which could affect the ownership of these assets and related revenues and expenses.
The retail 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. Federal governmental authorities are advocating the formation of RTOs and are proposing the adoption of new regulations that would impact electric markets, including the transmission regulatory structure. Under this new transmission regulatory structure, the retail operating companies would transfer functional control (but not ownership) of their transmission facilities to an independent third party. Because it remains unclear how RTOs will develop or what new market rules will be established, Southern Company is unable to assess fully the impact that these developments may have on its business. Southern Company's revenues, expenses, assets and liabilities could be adversely affected by changes in the transmission regulatory structure in its regional power market.
Recent events in the energy markets that are beyond Southern Company's control 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 Southern Company's business operations or the accounting treatment of its existing operations which could have a negative impact on Southern Company's net income or access to capital.
As a result of the energy crisis in California during the summer of 2001, the filing of bankruptcy by Enron Corporation, investigations by governmental authorities into energy trading activities and the August 2003 power outage in the Northeast, companies generally in the regulated and unregulated 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. The capital markets and ratings agencies also have increased their level of scrutiny. This increased scrutiny could lead to substantial changes in laws and regulations affecting Southern Company, including new accounting standards that could change the way Southern Company is required to record revenues, expenses, assets and liabilities. These types of disruptions in the industry and any resulting regulations may have a negative impact on Southern Company's net income or access to capital.
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Deregulation or restructuring in the electric industry may result in increased competition and unrecovered costs which could negatively impact Southern Company's earnings.
Increased competition which may result from restructuring efforts could have a significant adverse financial impact on Southern Company and its retail operating companies. Increased competition could result in increased pressure to lower the cost of electricity. Any adoption in the territories served by the retail operating companies of retail competition and the unbundling of regulated energy service could have a significant adverse financial impact on Southern Company and the retail 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 cannot predict if or when it will be subject to changes in legislation or regulation, nor can Southern Company predict the impact of these changes.
Additionally, the electric utility industry has experienced a substantial increase in competition at the wholesale level, caused by changes in federal law and regulatory policy. As a result of the Public Utility Regulatory Policies Act of 1978 and the Energy Act, competition in the wholesale electricity market has greatly increased due to a greater participation by traditional electricity suppliers, non-utility generators, independent power producers, wholesale power marketers and brokers, and due to the trading of energy futures contracts on various commodities exchanges. In 1996, the FERC issued new rules on transmission service to facilitate competition in the wholesale market on a nationwide basis. The rules give greater flexibility and more choices to wholesale power customers. Also, in July 2002, the FERC issued a notice of proposed rulemaking (which has not yet been adopted) related to open access transmission service and standard electricity market design. In addition, in April 2003, the FERC issued a White Paper in response to public comments received on such proposed rulemaking on standard electricity market design. Reactions to the White Paper by Southeastern state regulators reflect significant continuing differences in opinion between the FERC and various state regulatory commissions over questions of jurisdiction and protection of retail customers. As a result of the changing regulatory environment and the relatively low barriers to entry (which include, in addition to open access transmission service, relatively low construction costs for new generating facilities), Southern Company expects competition to steadily increase. This increased competition could affect Southern Company's load forecasts, plans for power supply and wholesale energy sales and related revenues. The effect on Southern Company's net income and financial condition could vary depending on the extent to which: (i) additional generation is built to compete in the wholesale market; (ii) new opportunities are created for Southern Company to expand its wholesale load; or (iii) current wholesale customers elect to purchase from other suppliers after existing contracts expire.
Southern Power currently has general authorization from the FERC to sell power to nonaffiliates at market-based prices. In addition, each of the retail operating companies has obtained FERC approval to sell power to nonaffiliates at market-based prices under specific contracts. Southern Power and the retail operating companies also have FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities' applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company, and found Southern Company and others to be "pivotal suppliers" in their service areas and ordered the implementation of several mitigation measures. Southern Company and others sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. Southern Company and others submitted comments to the FERC in 2002 regarding these issues. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. Southern Company anticipates that the FERC will address the requests for rehearing in the near future. Regardless of the outcome of the SMA proposal, the FERC retains the ability to modify or withdraw the authorization for any seller to sell at market-based rates, if it determines that the underlying conditions for having such authority are no longer applicable. In that event, Southern Power would be required to obtain FERC approval of rates based on cost of service, which may be lower than those in negotiated market-based rates. The final outcome of this matter will depend on the form in which the SMA test and mitigation measures' rules may be ultimately adopted and cannot be determined at this time.
PPAs by Georgia Power and Savannah Electric for Southern Power's Plant McIntosh capacity were certified by the Georgia PSC in December 2002 after a
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competitive bidding process. In April 2003, Southern Power applied for FERC approval of these PPAs. Interveners opposed the FERC's acceptance of the PPAs, alleging that the PPAs do not meet the applicable standards for market-based rates between affiliates. In July 2003, the FERC accepted the PPAs to become effective as scheduled on June 1, 2005, subject to refund, and ordered that hearings be held. For additional information, see Note 3 to the financial statements of Southern Company, Georgia Power, Savannah Electric and Southern Power under "FERC Matters" in Item 8 herein.
Risks Related to Environmental Regulation
Southern Company's costs of compliance with environmental laws are significant. The costs of compliance with future environmental laws and the incurrence of environmental liabilities could harm Southern Company's cash flow and profitability.
Southern Company and its subsidiaries 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 to commit significant expenditures for installation of pollution control equipment, environmental monitoring, emissions fees and permits at all of its facilities. These expenditures are significant and Southern Company expects that they will increase in the future. For example, construction expenditures for achieving compliance with Title IV of the Clean Air Act totaled approximately $400 million. Construction expenditures for compliance with the nitrogen oxide emission reduction requirements totaled approximately $980 million through 2003.
Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials and electromagnetic fields have become more frequent. Although the ultimate outcome of such litigation cannot be predicted, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the financial statements of Southern Company and its subsidiaries.
If Southern Company fails to comply with environmental laws and regulations, even if caused by factors beyond its control, that failure may result in the assessment of civil or criminal penalties and fines against Southern Company. The EPA has filed civil actions against Alabama Power, Georgia Power and Savannah Electric alleging violations of the new source review provisions of the Clean Air Act. The EPA has also issued notices of violation to Gulf Power and Mississippi Power. An adverse outcome in any one of these cases could require substantial capital expenditures that cannot be determined at this time and could require payment of substantial penalties.
Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to Southern Company. Revised or additional laws and regulations could result in significant additional expense and operating restrictions on Southern Company's facilities or increased compliance costs which may not be fully recoverable from Southern Company's customers and would therefore reduce Southern Company's net income. The cost impact of such legislation 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. 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 earnings 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 stock dividends. In addition, the Holding Company Act rules limit the dividends that Southern Company's subsidiaries may pay from unearned surplus. I-6
Southern Company's financial performance 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:
o operator error and breakdown or failure of equipment or processes; o operating limitations that may be imposed by environmental or other regulatory requirements; o labor disputes; o terrorist attacks; o fuel supply interruptions; and o catastrophic events such as fires, earthquakes, explosions, floods 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 Southern Company's net income and could decrease or eliminate funds available to Southern Company.
Southern Company's revenues 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 Southern Company's earnings.
Most of Southern Power's generating capacity under construction, or planned, has been sold to purchasers under PPAs having initial terms of five to 15 years. Southern Power's revenues are dependent on the continued performance by the purchasers of their obligations under the PPAs. Even though Southern Power has a rigorous credit evaluation, the failure of one of the purchasers to perform its obligations could have a negative impact on Southern Power's earnings. Although Southern Power's credit evaluations take into account the possibility of default by a purchaser, Southern Power's actual exposure to a default by a purchaser may be greater than Southern Power's credit evaluation predicts. Further, while the PPAs are currently a substantial portion of Southern Power's business, Southern Power cannot predict whether they 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, Southern Power cannot predict whether it will be replaced.
Southern Company and its subsidiaries may incur additional costs or delays in power plant construction and may not be able to recover their investment. Southern Company's facilities require ongoing capital expenditures.
Southern Power is in the process of constructing new generating facilities and intends to continue its strategy of developing and constructing other new facilities and expanding existing facilities. The completion of these facilities without delays or cost overruns is subject to substantial risks, including:
o shortages and inconsistent quality of equipment, materials and labor; o work stoppages; o permits, approvals and other regulatory matters; o adverse weather conditions; o unforeseen engineering problems; o environmental and geological conditions; o delays or increased costs to interconnect its facilities to transmission grids; o unanticipated cost increases; and o attention to other projects.
If Southern Power is unable to complete the development or construction of a facility, or if Southern Power decides to delay or cancel construction of a facility, Southern Power 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 Southern Power's results of operations and financial position. Furthermore, if construction projects are not completed according to specification, Southern Power may incur liabilities and suffer reduced plant efficiency, higher operating costs and reduced earnings.
Once facilities come into commercial operation, ongoing capital expenditures are required to maintain reliable levels of operation.
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Changes in technology may make Southern Company's electric generating facilities less competitive.
A key element of Southern Company's business model is that generating power at central power plants achieves economies of scale and produces power at relatively low cost. There are other technologies that produce power, most notably fuel cells, microturbines, windmills 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 power station electric production. If this were to happen and if these technologies achieved economies of scale, Southern Company's market share could be eroded, and the value of its electric generating facilities could be reduced. Changes in technology could also alter the channels through which retail electric customers buy power, which could reduce Southern Company's revenues or increase expenses.
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, and which may present potential exposures in excess of Southern Company's insurance coverage.
Southern Company owns six nuclear units through Alabama Power (two units) and through Georgia Power, which holds undivided interests in, and contracts for operation of, four units. These six nuclear units are operated by Southern Nuclear and represent approximately 3,680 megawatts, or 9.5% of Southern Company's generation capacity as of December 31, 2003. Southern Company's 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. Southern Company maintains 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 Southern Company's 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. Recent NRC orders related to increased security measures and any future safety requirements promulgated by the NRC could require Southern Company to make substantial operating and capital expenditures at its nuclear plants. In addition, although Southern Company has no reason to anticipate a serious nuclear incident at its plants, if an incident did occur, it could result in substantial costs to 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.
Southern Company's nuclear units require licenses that need to be renewed or extended in order to continue operating beyond their initial forty-year terms. As a result of potential terrorist threats and increased public scrutiny of utilities, the licensing process could result in increased licensing or compliance costs that are difficult or impossible to predict.
Southern Company's generation and energy marketing operations are subject to risks, many of which are beyond its control, that may reduce Southern Company's revenues and increase its costs.
Southern Company's generation and energy marketing operations are subject to changes in power prices or fuel costs, which could increase the cost of producing power or decrease the amount Southern Company receives from the sale of power. The market prices for these commodities may fluctuate over relatively short periods of time. Southern Company attempts to mitigate risks associated with fluctuating fuel costs by passing these costs on to customers in its PPAs. Among the factors that could influence power prices and fuel costs are:
o prevailing market prices for coal, natural gas, fuel oil and other fuels used in Southern Company's generation facilities, including associated transportation costs, and supplies of such commodities; o demand for energy and the extent of additional supplies of energy available from current or new competitors;
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o liquidity in the general wholesale electricity market; o weather conditions impacting demand for electricity; o seasonality; o transmission or transportation constraints or inefficiencies; o availability of competitively priced alternative energy sources; o economy in the service territory; o natural disasters, wars, embargos, acts of terrorism and other catastrophic events; and o federal, state and foreign energy and environmental regulation and legislation.
Certain of these factors could increase Southern Company's expenses. For the retail operating companies, such increases may not be fully recoverable through rates. Other of these factors could reduce Southern Company's revenues.
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 results of operations of Southern Company and its subsidiaries.
Southern Company and its subsidiaries 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.
Southern Company may not be able to obtain adequate fuel supplies, which could limit its ability to operate its facilities.
Southern Company purchases fuel from a number of suppliers. Disruption in the delivery of fuel, including disruptions as a result of, among other things, weather, labor relations or environmental regulations affecting Southern Company's fuel suppliers, could limit Southern Company's ability to operate its facilities, and thus, reduce its net income.
Demand for power could exceed Southern Company's supply capacity, resulting in increased costs to Southern Company for purchasing capacity in the open market or building additional generation capabilities.
Southern Company is currently obligated to supply power to regulated retail and wholesale customers. 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 Southern Company purchase capacity on the open market or build additional generation capabilities. Because regulators may not permit the retail operating companies to pass all of these purchase or construction costs on to their customers, the retail 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 retail 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.
Southern Company's operating results are affected by weather conditions and may fluctuate on a seasonal and quarterly basis.
Electric power generation is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. As a result, Southern Company's overall operating results in the future may fluctuate substantially on a seasonal basis. In addition, Southern Company has historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could reduce Southern Company's revenues, net income, available cash and borrowing ability.
Risks Related to Market and Economic Volatility
Southern Company's business is dependent on its ability to successfully access capital markets. Southern Company's inability to access capital may limit its ability to execute its business plan or pursue improvements and make acquisitions that Southern Company may otherwise rely on for future growth.
Southern Company relies 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 its operations. If Southern
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Company 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 may otherwise rely on for future growth will be limited. Southern Company believes that it will maintain sufficient access to these financial markets based upon current credit ratings. However, certain market disruptions or a downgrade of Southern Company's credit rating 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:
o an economic downturn; o the bankruptcy of an unrelated energy company; o capital market conditions generally; o market prices for electricity and gas; o terrorist attacks or threatened attacks on Southern Company's facilities or unrelated energy companies; o war or threat of war; or o the overall health of the utility industry.
Southern Company is subject to risks associated with a changing economic environment, including Southern Company's ability to obtain insurance, the financial stability of its customers and Southern Company's ability to raise capital.
Due to the September 11, 2001 terrorist attacks and the resulting ongoing war against terrorism by the United States, the nation's economy and financial markets were disrupted in general. The insurance industry has also been disrupted by these events. The availability of insurance covering risks Southern Company and its competitors typically insure against may decrease, and the insurance that Southern Company is able to obtain may have higher deductibles, higher premiums and more restrictive policy terms. Any economic downturn or disruption of financial markets could constrain the capital available to Southern Company's industry and could reduce Southern Company's access to funding for its operations, as well as the financial stability of its 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 earnings.
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. Construction expenditures during 2004 through 2006 by the retail operating companies, Southern Power, SEGCO, SCS, Southern LINC and other subsidiaries are estimated as follows:
------------------------------------------------------------ 2004 2005 2006 -------------------------------- (in millions) Alabama Power $ 791 $ 863 $ 884 Georgia Power 747 812 1,043 Gulf Power 166 149 108 Mississippi Power 80 70 98 Savannah Electric 52 43 41 Southern Power 259 254 356 SEGCO 13 9 7 SCS 27 24 20 Southern LINC 22 22 20 Other 7 3 2 ------------------------------------------------------------ Southern Company system $2,164 $2,249 $2,579 ================================================================
Also included in the foregoing construction expenditure estimates are the estimates for environmental expenditures. Reference is made to each registrant's "Management Discussion and Analysis - Capital Requirements and Contractual Obligations" in Item 7 herein for information on estimated environmental expenditures.
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*SCS, Southern LINC and other businesses plan capital additions to general plant in 2004 of $27 million, $22 million and $7 million, respectively, while SEGCO plans capital additions of $12 million to generating facilities and $1 million to transmission facilities. (See Item 1 - BUSINESS - "Other Business" herein.)
The construction programs are subject to periodic review and revision, and actual construction costs may vary from the above estimates because of changes in such factors as: business conditions; acquisition of additional generating assets; environmental regulations; nuclear plant regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment and materials; and cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Southern Company has approximately 1,200 megawatts of new generating capacity scheduled to be placed in service by 2005. The additional new capacity will be dedicated to the wholesale market and owned by Southern Power. Reference is made to Note 3 to the financial statements of Southern Company, Georgia Power, Savannah Electric and Southern Power in Item 8 herein under the heading "FERC Matters" for additional information regarding contracts for this capacity. In addition, capital improvements, including those needed to meet the environmental standards previously discussed for the retail operating companies' generation, transmission, and distribution facilities are ongoing.
Under Georgia law, Georgia Power and Savannah Electric each are required to file an Integrated Resource Plan for approval by the Georgia PSC. Under the plan rules, the Georgia PSC must pre-certify the construction of new power plants and new PPAs. (See Item 1 - BUSINESS - "Rate Matters - Integrated Resource Planning" herein and Note 3 to the financial statements of Southern Company in Item 8 herein under the heading "FERC Matters" for information regarding PPAs by Georgia Power and Savannah Electric for Southern Power's Plant McIntosh capacity.)
See Item 1 - BUSINESS - "Regulation - Environmental Statutes and Regulations" herein for information with respect to certain existing and proposed environmental requirements and Item 2
Item 2. PROPERTIES
Electric Properties - The Electric Utilities
The retail operating companies, Southern Power and SEGCO, at December 31, 2003, owned and/or operated 34 hydroelectric generating stations, 32 fossil fuel generating stations, three nuclear generating stations and 10 combined cycle/cogeneration stations. The amounts of capacity for each company are shown in the table below.
--------------------------------------------------------------- Nameplate Generating Station Location Capacity (1) --------------------------------------------------------------- (Kilowatts) Fossil Steam Gadsden Gadsden, AL 120,000 Gorgas Jasper, AL 1,221,250 Barry Mobile, AL 1,525,000 Greene County Demopolis, AL 300,000 (2) Gaston Unit 5 Wilsonville, AL 880,000 Miller Birmingham, AL 2,532,288 (3) --------- Alabama Power Total 6,578,538 ---------
Bowen Cartersville, GA 3,160,000 Branch Milledgeville, GA 1,539,700 Hammond Rome, GA 800,000 McDonough Atlanta, GA 490,000 McManus Brunswick, GA 115,000 Mitchell Albany, GA 125,000 Scherer Macon, GA 750,924 (4) Wansley Carrollton, GA 925,550 (5) Yates Newnan, GA 1,250,000 --------- Georgia Power Total 9,156,174 ---------
Crist Pensacola, FL 1,022,500 Lansing Smith Panama City, FL 305,000 Scholz Chattahoochee, FL 80,000 Daniel Pascagoula, MS 500,000 (6) Scherer Unit 3 Macon, GA 204,500 (4) ----------- Gulf Power Total 2,112,000 ---------
Eaton Hattiesburg, MS 67,500 Sweatt Meridian, MS 80,000 Watson Gulfport, MS 1,012,000 Daniel Pascagoula, MS 500,000 (6) Greene County Demopolis, AL 200,000 (2) ----------- Mississippi Power Total 1,859,500 -----------
---------------------------------------------------------------
---------------------------------------------------------------- Nameplate Generating Station Location Capacity ---------------------------------------------------------------- (Kilowatts) McIntosh Effingham County, GA 163,117 Kraft Port Wentworth, GA 281,136 Riverside Savannah, GA 102,278 ----------- Savannah Electric Total 546,531 -----------
Gaston Units 1-4 Wilsonville, AL SEGCO Total 1,000,000 (7) ----------- Total Fossil Steam 21,252,743 -----------
Nuclear Steam Farley Dothan, AL Alabama Power Total 1,720,000 -----------
Hatch Baxley, GA 899,612 (8) Vogtle Augusta, GA 1,060,240 (9) ----------- Georgia Power Total 1,959,852 ---------- Total Nuclear Steam 3,679,852 -----------
Combustion Turbines Greene County Demopolis, AL Alabama Power Total 720,000 -----------
Bowen Cartersville, GA 39,400 Intercession City Intercession City, FL 47,667 (10) McDonough Atlanta, GA 78,800 McIntosh Units 1,2,3,4,7,8 Effingham County, GA 480,000 McManus Brunswick, GA 481,700 Mitchell Albany, GA 118,200 Robins Warner Robins, GA 160,000 Wansley Carrollton, GA 26,322 Wilson Augusta, GA 354,100 ----------- Georgia Power Total 1,786,189 ------------
Lansing Smith Unit A Panama City, FL 39,400 Pea Ridge Units 1-3 Pea Ridge, FL 15,000 ------ Gulf Power Total 54,400 ------
Chevron Cogenerating Station Pascagoula, MS 147,292 (11) Sweatt Meridian, MS 39,400 Watson Gulfport, MS 39,360 --------- Mississippi Power Total 226,052 ---------
Boulevard Savannah, GA 59,100 Kraft Port Wentworth, GA 22,000 McIntosh Units Effingham 5&6 County, GA 160,000 ------- Savannah Electric Total 241,100 -------
------------------------------------------------------------------ I-23
----------------------------------------------------------------- Generating Station Location Nameplate Capacity ----------------------------------------------------------------- (Kilowatts)
Dahlberg Jackson County, GA Southern Power Total 756,000 ----------
Gaston (SEGCO) Wilsonville, AL 19,680 (7) ----------- Total Combustion Turbines 3,803,421 -----------
Cogeneration Washington County Washington County, AL 123,428 GE Plastics Project Burkeville, AL 104,800 Theodore Theodore, AL 236,418 ----------- Alabama Power Total 464,646 -----------
Combined Cycle Barry Mobile, AL Alabama Power Total 1,070,424 ---------
Smith Lynn Haven, FL Gulf Power Total 619,650 -------
Daniel (Leased) Pascagoula, MS Mississippi Power Total 1,070,424 ---------
Stanton Unit A Orlando, FL 428,649(13) Harris Autaugaville, AL 1,318,920 Franklin Smiths, AL 1,198,360 Wansley Carrollton, GA 1,073,000 --------- Southern Power Total 4,018,929 --------- Total Combined Cycle 6,779,427 ---------
Hydroelectric Facilities
Weiss Leesburg, AL 87,750 Henry Ohatchee, AL 72,900 Logan Martin Vincent, AL 128,250 Lay Clanton, AL 177,000 Mitchell Verbena, AL 170,000 Jordan Wetumpka, AL 100,000 Bouldin Wetumpka, AL 225,000 Harris Wedowee, AL 135,000 Martin Dadeville, AL 175,000 Yates Tallassee, AL 32,000 Thurlow Tallassee, AL 60,000 Lewis Smith Jasper, AL 157,500 Bankhead Holt, AL 54,000 Holt Holt, AL 46,000 ----------- Alabama Power Total 1,620,400 -----------
------------------------------------------------------------------ Generating Station Location Nameplate Capacity ------------------------------------------------------------------ (Kilowatts) Barnett Shoals (Leased) Athens, GA 2,800 Bartletts Ferry Columbus, GA 173,000 Goat Rock Columbus, GA 26,000 Lloyd Shoals Jackson, GA 14,400 Morgan Falls Atlanta, GA 16,800 North Highlands Columbus, GA 29,600 Oliver Dam Columbus, GA 60,000 Rocky Mountain Rome, GA 215,256 (12) Sinclair Dam Milledgeville, GA 45,000 Tallulah Falls Clayton, GA 72,000 Terrora Clayton, GA 16,000 Tugalo Clayton, GA 45,000 Wallace Dam Eatonton, GA 321,300 Yonah Toccoa, GA 22,500 6 Other Plants 18,080 ----------- Georgia Power Total 1,077,736 ----------- Total Hydroelectric Facilities 2,698,136 -----------
Total Generating Capacity 38,678,225 ===========
------------------------------------------------------------------ Notes: (1) For additional information regarding facilities jointly-owned with non-affiliated parties, see Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein. (2) Owned by Alabama Power and Mississippi Power as tenants in common in the proportions of 60% and 40%, respectively. (3) Excludes the capacity owned by AEC. (4) Capacity shown for Georgia Power is 8.4% of Units 1 and 2 and 75% of Unit 3. Capacity shown for Gulf Power is 25% of Unit 3. (5) Capacity shown is Georgia Power's portion (53.5%) of total plant capacity. (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 Item 1 - BUSINESS herein.) (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. FPC operates the unit. (11)Generation is dedicated to a single industrial customer. (12)Capacity shown is Georgia Power's portion (25.4%) of total plant capacity. OPC operates the plant. (13)Capacity shown is Southern Power's portion (65%) of total plant capacity.
Except as discussed below under "Titles to Property," the principal plants and other important units of the retail operating companies, Southern Power and
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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, 2003, the unamortized portion of this cost was approximately $30.6 million.
The all-time maximum demand on the retail operating companies, Southern Power and SEGCO was 32,949,200 kilowatts and occurred in August 2003. This amount excludes demand served by capacity retained by MEAG and Dalton and excludes demand associated with power purchased from OPC and SEPA by its preference customers. The reserve margin for the retail operating companies, Southern Power and SEGCO at that time was 21.4%. For additional information on peak demands, reference is made to Item 6 - SELECTED FINANCIAL DATA herein.
Jointly-Owned Facilities
Alabama Power and Georgia Power have sold and Georgia Power has purchased undivided interests in certain generating plants and other related facilities to or from non-affiliated parties. Southern Power also owns an undivided interest in a facility with non-affiliated parties. The percentages of ownership resulting from these transactions 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 Unit A.
In addition, Georgia Power has commitments regarding a portion of a 5 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 1987 and 1990 write-offs 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.
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Titles to Property
The retail 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 of applicable mortgage indentures of Alabama Power, Gulf Power, Mississippi Power and Savannah Electric and to excepted encumbrances as defined therein. The retail operating companies own the fee interests in certain of their principal plants as tenants in common. (See Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein.) 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)
In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against Alabama Power, Georgia Power, and SCS. The complaint alleged violations of the New Source Review (NSR) provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia and violations of related state laws. The civil action requested penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued to the retail operating companies notices of violation relating to 10 generating facilities, which include the five facilities mentioned previously. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notices of violation and to add Gulf Power, Mississippi Power, and Savannah Electric as defendants.
In August 2000, the U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and granted SCS' motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. In March 2001, the court granted the EPA's motion to add Savannah Electric as a defendant, but it denied the motion to add Gulf Power and Mississippi Power based on lack of jurisdiction in Georgia over those companies. As directed by the court, the EPA refiled its amended complaint limiting claims to those brought against Georgia Power and Savannah Electric. In addition, the EPA refiled its claims against Alabama Power in the U.S. District Court for the Northern District of Alabama. These complaints allege violations with respect to eight coal-fired generating facilities in Alabama and Georgia, and they request the same kinds of relief as was requested in the original complaint, i.e. penalties and injunctive relief, including installation of the best available control technology. The EPA has not refiled against Gulf Power, Mississippi Power, or SCS.
The actions against Alabama Power, Georgia Power, and Savannah Electric were stayed in the spring of 2001 during the appeal of a very similar NSR enforcement action against the Tennessee Valley Authority (TVA) before the U.S. Court of Appeals for the Eleventh Circuit. The TVA appeal involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and Savannah Electric. Because the final resolution of the TVA appeal could have a significant impact on Alabama Power and Georgia Power, both companies have been involved in that appeal. On June 24, 2003, the court of appeals issued its ruling in the TVA case. It found unconstitutional the statutory scheme set forth in the Clean Air Act that allowed the EPA to impose penalties for failing to comply with an administrative compliance order, like the one issued to TVA, without the EPA having to prove the underlying violation. Thus, the court of appeals held that the compliance order was of no legal consequence, and TVA was free to ignore it. The court did not, however, rule directly on the substantive legal issues about the proper interpretation and application of certain NSR provisions that had been raised in the TVA appeal. On September 16, 2003, the court of appeals denied the EPA's request for a rehearing of the decision. On February 13, 2004, the EPA petitioned the U.S. Supreme Court to review the decision of the court of appeals. The EPA also filed a motion to lift the stay in the action against Alabama Power. At this time, no party to the Georgia Power and Savannah Electric action, which was administratively closed two years ago, has asked the court to reopen that case.
Since the inception of the NSR proceedings against Georgia Power, Alabama Power, and Savannah Electric, the EPA has also been proceeding with similar NSR enforcement actions against other utilities, involving many of the same legal issues. In each case, the EPA alleged that the
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Item 3. LEGAL PROCEEDINGS (Continued)
utilities failed to comply with the NSR permitting requirements when performing maintenance and construction activities at coal-burning plants, which activities the utilities considered to be routine or otherwise not subject to NSR. In 2003, district courts addressing these cases have issued opinions that reached conflicting conclusions.
In October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act clarifying the scope of the existing Routine Maintenance, Repair, and Replacement exclusion. On December 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit stayed the effectiveness of these revisions pending resolution of related litigation. In January 2004, the Bush Administration announced that it would continue to enforce the existing rules.
Southern Company believes that its retail operating companies complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome in any one of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
(2) Cooper et al. v. Georgia Power, Southern Company, SCS and Energy Solutions (Superior Court of Fulton County, Georgia)
In July 2000, a lawsuit alleging race discrimination was filed by three Georgia Power employees against Georgia Power, Southern Company, and SCS in the Superior Court of Fulton County, Georgia. Shortly thereafter, the lawsuit was removed to the United States District Court for the Northern District of Georgia. The lawsuit also raised claims on behalf of a purported class. The plaintiffs seek compensatory and punitive damages in an unspecified amount, as well as injunctive relief. In August 2000, the lawsuit was amended to add four more plaintiffs. Also, an additional indirect subsidiary of Southern Company, Energy Solutions, was named a defendant.
In October 2001, the district court denied the plaintiffs' motion for class certification. The plaintiffs filed a motion to reconsider the order denying class certification, and the court denied the plaintiffs' motion to reconsider. In December 2001, the plaintiffs filed a petition in the U.S. Court of Appeals for the Eleventh Circuit seeking permission to file an appeal of the October 2001 decision, and this petition was denied. After discovery was completed on the claims raised by the seven named plaintiffs, the defendants filed motions for summary judgment on all of the named plaintiffs' claims. On March 31, 2003, the U.S. District Court for the Northern District of Georgia granted summary judgment in favor of the defendants on all claims raised by all seven plaintiffs. On April 23, 2003, plaintiffs filed an appeal to the U.S. Court of Appeals for the Eleventh Circuit challenging these adverse summary judgment rulings, as well as the District Court's October 2001 ruling denying class certification. Oral argument occurred on January 27, 2004, and the parties await the court's decision. The final outcome of this matter cannot now be determined.
(3) Georgia Power Potentially Responsible Party
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. Georgia Power has recognized $34 million in
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Item 3. LEGAL PROCEEDINGS (Continued)
cumulative expenses through December 31, 2003, for the assessment and anticipated cleanup of sites on the Georgia Hazardous Sites Inventory. In addition, in 1995 the EPA designated Georgia Power and four other unrelated entities as potentially responsible parties at a site in Brunswick, Georgia that is listed on the federal National Priorities List. Georgia Power has contributed to the removal and remedial investigation and feasibility study costs for the site. Additional claims for recovery of natural resource damages at the site are anticipated. As of December 31, 2003, Georgia Power had recorded approximately $6 million in cumulative expenses associated with Georgia Power's agreed upon share of the removal and remedial investigation and feasibility study costs for the Brunswick site.
The final outcome of each of these matters cannot now be determined. However, based on the currently known conditions at these sites and the nature and extent of Georgia Power's activities relating to these sites, management does not believe that Georgia Power's additional liability, if any, at these sites would be material to the financial statements.
Reference is made to Note 3 to Southern Company's and Georgia Power's financial statements in Item 8 herein under the headings "Georgia Power Potentially Responsible Party Status" and "Potentially Responsible Party Status," respectively.
(4) In re: Mobile Energy Services Company, LLC; In re: Mobile Energy Services Holdings, Inc. (U.S. Bankruptcy Court for the Southern District of Alabama)
MESH is the owner and operator of a facility that generates electricity, produces steam, and processes black liquor as part of a pulp and paper complex in Mobile, Alabama. In January 1999, MESH filed a petition for Chapter 11 bankruptcy with the U.S. Bankruptcy Court. In 2001, MESH filed an amended plan of reorganization, which the U.S. Bankruptcy Court confirmed in September 2003. The plan became effective in late 2003 and Southern Company's equity interest in MESH - which had been written off entirely prior to 2001 - was extinguished. Southern Company will continue to have contingent liabilities to the pulp and paper complex owners associated with a guarantee of certain potential environmental obligations and with a potential obligation to fund a maintenance reserve account that expires in 2019 and 2021, respectively. The combined maximum contingent liabilities were $19 million at December 31, 2003. MESH and Mirant have each separately agreed to indemnify Southern Company for any amounts required to be paid under such obligations. The final outcome of these matters cannot now be determined.
(5) California Electricity Markets Investigation
Southern Company received a subpoena in November 2002 to provide information to a federal grand jury in the Northern District of California. The subpoena covered a number of broad areas, including specific information regarding electricity production and sales activities in California. Mirant participated in energy marketing and trading in California during the period relevant to the subpoena. Southern Company has produced documents in response to the subpoena and has fully cooperated in the investigation.
(6) In re: Mirant Corporation, et. al (U.S. Bankruptcy Court for the Northern District of Texas)
On July 14, 2003, Mirant filed for voluntary reorganization under Chapter 11 with the U.S. Bankruptcy Court. Southern Company has certain contingent liabilities associated with guarantees of contractual commitments made by Mirant's subsidiaries discussed in Note 7 to Southern Company's financial statements in Item 8 herein under "Guarantees" and with various lawsuits related to Mirant
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Item 3. LEGAL PROCEEDINGS (Continued)
discussed elsewhere in this Item 3. Also, Southern Company has joint and several liability with Mirant regarding the joint consolidated federal income tax return as discussed in Note 5 to the financial statements of Southern Company in Item 8 herein. Under the terms of the separation agreement, Mirant agreed to indemnify Southern Company for costs associated with these guarantees, lawsuits, and additional Internal Revenue Service (IRS) assessments. The impact of Mirant's bankruptcy filing on Mirant's indemnity obligations, if any, cannot now be determined. If Southern Company is ultimately required to make any payments related to these potentially material obligations, Mirant's indemnification obligation to Southern Company would represent an unsecured pre-bankruptcy claim, subject to compromise pursuant to Mirant's final reorganization plan.
The Bankruptcy Code automatically stays all litigation as to Mirant. A motion filed with the bankruptcy court requesting an extension of this automatic stay to all other non-debtor defendants, including Southern Company and the named current and/or former Southern Company officers was granted in November 2003. Although the Mirant securities litigation is stayed until further order from the bankruptcy court, Mirant is authorized to agree with parties in pending actions to allow discovery or other matters to proceed without violating the stay. Mirant and plaintiffs' counsel in the Mirant securities litigation have agreed that document discovery may proceed. On October 23, 2003, the bankruptcy court entered an order authorizing Southern Company's insurance companies to pay related defense costs.
On February 20, 2004, the Official Committee of Unsecured Creditors of Mirant informed Southern Company of its intent to examine Southern Company in accordance with federal bankruptcy rules to determine whether there is a legitimate basis to bring claims against Southern Company in connection with Mirant's initial public offering, Southern Company's spin off of Mirant and the related separation agreements.
The final outcome of these matters cannot now be determined.
(7) In re: Mirant Corporation Securities Litigation (United States District Court for the Northern District of Georgia)
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 putative class action lawsuit that several Mirant shareholders originally filed against Mirant and certain Mirant officers in May 2002. The original lawsuit was based on allegations related to alleged improper energy trading and marketing activities involving the California energy market. 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.
On July 14, 2003, the court dismissed all claims based on Mirant's alleged improper energy trading and marketing activities involving the California energy market. The remaining claims are based on alleged false statements and omissions in Mirant's prospectus for its initial public offering and accounting-related issues previously disclosed by Mirant.
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Item 3. LEGAL PROCEEDINGS (Continued)
Such claims do not allege any improper trading and marketing activity, accounting errors, or material misstatements or omissions on the part of Southern Company, but rather 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 on September 3, 2003. Plaintiffs have also filed a motion for class certification.
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 are also named as defendants in this lawsuit. Except for limited document discovery, litigation has been stayed until further order from the bankruptcy court. The final outcome of these matters cannot now be determined.
(8) In re: Mirant Corporation ERISA Litigation (United States District Court for the Northern District of Georgia)
In April 2003, a retired employee of Mirant filed a complaint in the U.S. District Court for the Northern District of Georgia alleging violations of ERISA and naming as defendants Mirant, Southern Company, several current and former directors and officers of Mirant and/or Southern Company, and "Unknown Fiduciary Defendants 1-100." In June 2003, a substantially similar complaint was filed. Neither complaint contained any specific allegations of wrongdoing with respect to Southern Company. On September 2, 2003, the court consolidated all pending and future ERISA actions arising out of the same facts, and the plaintiffs filed a consolidated amended ERISA complaint on September 23, 2003. The plaintiffs sought to represent a class of persons who were participants in or beneficiaries of certain Mirant employee benefit plans between September 27, 2000, and July 22, 2003. The consolidated amended complaint named as defendants Mirant, certain Mirant benefit committees, Southern Company, and several of Mirant's current and former officers, directors, and employees. The consolidated amended complaint alleged that the defendants breached their fiduciary duties and violated ERISA by failing to investigate whether Mirant stock was a prudent investment for the plans, by continuing and promoting Mirant stock as an investment alternative for participants in the plans, and by failing to disclose information about Mirant's financial condition and about its improper activities in the California energy markets.
On February 19, 2004, the plaintiffs dismissed Southern Company from this action without prejudice. The plaintiffs are not barred from naming Southern Company in some future lawsuit, but management believes the possibility of having to pay damages in any such lawsuit is remote.
(9) Sierra Club, et al v. Georgia Power (United States District Court for the Northern District of Georgia)
On December 30, 2002, the Sierra Club, Physicians for Social Responsibility, Georgia ForestWatch, and one individual filed a civil suit in the U.S. District Court in Georgia against Georgia Power for alleged violations of the Clean Air Act at four of the generating units at Plant Wansley. The complaint alleges Clean Air Act violations at both the existing coal-fired units and the new combined cycle units. Specifically, the plaintiffs allege (1) opacity violations at the coal-fired units, (2) violations of a permit provision that requires the combined cycle units to operate above certain levels, (3) violation of nitrogen oxide emission offset requirements, and (4) violation of hazardous air pollutant requirements. The civil action requests injunctive and declaratory relief, civil penalties, a supplemental environmental project, and attorneys' fees. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit.
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Item 3. LEGAL PROCEEDINGS (Continued)
On June 19, 2003, the court granted Georgia Power's motion to dismiss the allegations regarding hazardous air pollutants and denied Georgia Power's motion to dismiss the allegations regarding emission offsets. On August 29, 2003, Georgia Power filed a motion for partial summary judgment regarding emission offsets. On January 20, 2004, Georgia Power filed a motion for summary judgment on the remaining three counts, and the plaintiffs have filed motions for partial summary judgment. The case is currently scheduled for trial during the summer of 2004. While Georgia Power believes that it has complied with applicable laws and regulations, an adverse outcome could require payment of substantial penalties. The final outcome of this matter cannot now be determined.
(10) Right of Way Litigation
Southern Company and certain of its subsidiaries, including Georgia Power, Gulf Power, Mississippi Power, and Southern Telecom (collectively, defendants), have been named as defendants in numerous lawsuits brought by landowners since 2001 regarding the installation and use of fiber optic cable over defendants' rights of way located on the landowners' property. 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 by defendants exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment. The plaintiffs seek compensatory and punitive damages and injunctive relief. With respect to 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, on November 7, 2003, the Second Circuit Court in Gadsden County, Florida, ruled in favor of the plaintiffs on their motion for partial summary judgment concerning liability. The question of damages, if any, will be decided at a future trial. In the event of an adverse verdict on damages, Gulf Power could appeal the verdicts on both liability and damages. Management of Southern Company and its subsidiaries believe that the defendant companies in the pending right of way litigation have complied with applicable laws and that the plaintiffs' claims are without merit. An adverse outcome in these matters could result in substantial judgments; however, the final outcome of these matters cannot now be determined.
In addition, in late 2001, certain subsidiaries of Southern Company, including Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, and Southern Telecom (collectively, defendants), 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 the telecommunications company in pending and future right of way litigation. The defendants believe that the plaintiff's claims are without merit. 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.
(11) Jerry A. Carter v. Gulf Power
On January 28, 2003, a jury in Escambia County, Florida, returned a verdict of $3 million against Gulf Power arising out of an alleged electrical injury sustained by the plaintiff in January 1999 while inside his apartment. This matter is on appeal to Florida's First District Court of Appeal. If this verdict is upheld, there is insurance coverage available to offset a substantial portion of this amount. The ultimate outcome of this matter cannot now be determined, but is not expected to have a material impact on Gulf Power's financial statements.
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Item 3. LEGAL PROCEEDINGS (Continued)
Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the business activities of Southern Company and its subsidiaries are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury and citizen enforcement of environmental requirements, 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 litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the financial statements of Southern Company and its subsidiaries.
See Item 1 - BUSINESS - "Construction Programs," "Fuel Supply," "Regulation - - Federal Power Act" and "Rate Matters" as well as Note 3 to each registrant's financial statements in Item 8 herein for a description of certain other administrative and legal proceedings discussed therein.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
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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, 2003.
H. Allen Franklin (1) Chairman, President, Chief Executive Officer and Director Age 59 Elected Director in 1988 and Chief Executive Officer effective March 1, 2001. Previously served as President and Chief Operating Officer of Southern Company from June 1999 to March 2001; and as President and Chief Executive Officer of Georgia Power from January 1994 to June 1999.
Dwight H. Evans Executive Vice President Age 55 Elected in 2001. Previously served as President and Chief Executive Officer of Mississippi Power from March 1995 to May 2001.
Thomas A. Fanning Executive Vice President, Chief Financial Officer and Treasurer Age 46 Elected in 2003. Previously served as President, Chief Executive Officer and Director of Gulf Power from 2002 to April 2003; Executive Vice President, Treasurer and Chief Financial Officer of Georgia Power from 1999 to 2002.
Leonard J. Haynes Executive Vice President and Chief Marketing Officer Age 53 Elected in 2001. Previously served as Senior Vice President of Georgia Power from October 1998 to May 2001; and Vice President of Georgia Power from October 1992 to October 1998.
G. Edison Holland, Jr. Executive Vice President Age 51 Elected in 2001. Previously served as President and Chief Executive Officer of Savannah Electric from 1997 until 2001.
Charles D. McCrary Executive Vice President Age 52 Elected in 1998. He also serves as President and Chief Executive Officer of Alabama Power since October 2001 and Executive Vice President of Southern Company since February 2002. Previously served as President and Chief Operating Officer of Alabama Power from April 2001 to October 2001; Vice President of Southern Company from February 1998 to April 2001.
David M. Ratcliffe (2) Executive Vice President Age 55 Elected in 1999. He also has served as Chief Executive Officer of Georgia Power since June 1999 and as President of Georgia Power from June 1999 to December 2003. Previously served as Executive Vice President, Treasurer and Chief Financial Officer of Georgia Power from March 1998 to June 1999.
W. Paul Bowers President of Southern Company Generation & Energy Marketing, Executive Vice President of SCS and President and Chief Executive Officer of Southern Power since May 2001 Age 47 Elected in 2001. Previously served as Senior Vice President and Chief Marketing Officer of Southern Company from March 2000 to May 2001; President and Chief Executive Officer of Western Power Distribution and Southwestern Electricity plc, a subsidiary of Mirant located in Bristol, England, from December 1998 to 2000.
W. G. Hairston, III President and Chief Executive Officer of Southern Nuclear since 1993. Age 59
(1) Mr. Franklin will retire in July 2004.
(2) Mr. Ratcliffe will continue to serve as Chief Executive Officer of Georgia Power until April 2004, at which time he will become President of Southern Company. He will become Chairman and Chief Executive Officer of Southern Company effective in July 2004.
The officers of Southern Company were elected for a term running from the first meeting of the directors following the last annual meeting (May 22, 2003)
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for one year until the first board meeting after the next annual meeting or until their successors are elected and have qualified.
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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, 2003.
Charles D. McCrary President, Chief Executive Officer and Director Age 52 Elected in 2001. Served as President and Chief Operating Officer of Alabama Power from April 2001 to October 2001 and Vice President of Southern Company from February 1998 to April 2001.
William B. Hutchins, III Executive Vice President, Chief Financial Officer and Treasurer Age 60 Elected in 1991. Served as Treasurer since 1998 in addition to Executive Vice President and Chief Financial Officer since 1994.
C. Alan Martin Executive Vice President Age 55 Elected in 1999. Served as Executive Vice President of External Affairs from January 2000 to April 2001. Previously served as Executive Vice President and Chief Marketing Officer for Southern Company from 1998 to 1999.
Steven R. Spencer Executive Vice President Age 48 Elected in 2001. Served as Senior Vice President of External Affairs from July 2000 to April 2001. Previously served as Vice President of Southern Company's external affairs organization from 1998 to 2001.
Jerry L. Stewart Senior Vice President Age 54 Elected in 1999. Served as Senior Vice President of Fossil and Hydro Generation since 1999. Previously served as Vice President of SCS from 1992 to 1999.
The officers of Alabama Power were elected for a term running from the last annual meeting of the directors (April 25, 2003) for one year until the next annual meeting or until their successors are elected and have qualified.
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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, 2003.
David M. Ratcliffe (1) Chief Executive Officer and Director Age 55 Elected as an Executive Officer in 1998 and as Director in 1999. Served as Chief Executive Officer since June 1999 and as President from June 1999 through December 2003. Previously served as Executive Vice President, Treasurer and Chief Financial Officer of Georgia Power from March 1998 to June 1999.
Michael D. Garrett (2) President and Director Age 54 Elected in 2003. President and Director of Georgia Power effective January 1, 2004. Previously served as President, Chief Executive Officer and Director of Mississippi Power from 2001 to 2003; Executive Vice President - Customer Service of Alabama Power from January 2000 to May 2001; and Executive Vice President of External Affairs of Alabama Power from March 1998 to January 2000.
William C. Archer, III Executive Vice President Age 55 Elected in 1995. Served as Executive Vice President of External Affairs since 1995.
C. B. Harreld Executive Vice President, Chief Financial Officer and Treasurer Age 59 Elected in 2003. Served as Executive Vice President, Chief Financial Officer and Treasurer since 2003. Previously served as Senior Vice President of Finance, SCS from 2002 to 2003; Chief Financial Officer and Comptroller of Southern Company Generation and Energy Marketing from 2001 to 2002; Chief Financial Officer of Mirant - Europe from 2000 to 2001; and Vice President and Controller, Southern Energy, Inc. from 1999 to 2000.
Judy M. Anderson Senior Vice President Age 55 Elected in 2001. Served as Senior Vice President of Charitable Giving since 2001. Previously served as Vice President and Corporate Secretary of Georgia Power from 1989 to 2001.
Ronnie L. Bates Senior Vice President Age 49 Elected in 2001. Served as Senior Vice President, Planning, Sales and Service since 2001. Previously served as Vice President, Transmission from 2000 to 2001; and as General Manager, Transmission and Construction from 1995 to 2000.
Mickey A. Brown Senior Vice President Age 56 Elected in 2001. Served as Senior Vice President of Distribution since 2001. Previously served as Vice President, Distribution from 2000 to 2001; and as Vice President, Northern Region from 1993 to 2000.
Richard L. Holmes Senior Vice President Age 52 Elected in 2003. Served as Senior Vice President of Corporate Services since 2003. Previously served as Vice President of Corporate Services from 2002 to 2003; Vice President of Region Operations from 2000 to 2002; Assistant to the President and Chief Executive Officer from 1999 to 2000; and Metro West Region Manager from 1992 to 1999.
Leslie R. Sibert Vice President Age 41 Elected in 2001. Served as Vice President, Transmission since 2001. Previously served as Decatur Region Manager from 1999 to 2001; and as Assistant to Senior Vice President, Southern Wholesale Energy from 1996 to 1999.
Christopher C. Womack Senior Vice President Age 45 Elected in 2001. Served as Senior Vice President of Fossil and Hydro since 2001. Previously served as Vice President and Chief Executive People Officer of Southern Company from 1998 to 2001.
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(1) Mr. Ratcliffe will continue to serve as Chief Executive Officer of Georgia Power until April 2004, at which time he will become President of Southern Company. He will become Chairman and Chief Executive Officer of Southern Company in July 2004.
(2) Mr. Garrett was elected President and Director of Georgia Power effective January 1, 2004. In addition, he will become Chief Executive Officer of Georgia Power effective April 2004.
The officers of Georgia Power were elected for a term running from the last annual meeting of the directors (May 21, 2003) for one year until the next annual meeting or until their successors are elected and have qualified, except for Mr. Harreld whose election was effective June 30, 2003 and Mr. Garrett whose election was effective January 1, 2004.
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EXECUTIVE OFFICERS OF GULF POWER
(Identification of executive officers of Gulf 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, 2003.
Susan N. Story President, Chief Executive Officer and Director Age 43 Elected in 2003. Previously served as Executive Vice President of Engineering and Construction Services at Southern Company Generation and Energy Marketing from 2001 to 2003; Vice President of Procurement and Materials at SCS from 2000 to 2001; and Vice President of Corporate Services and Corporate Real Estate at Alabama Power from 1997 to 2000.
Francis M. Fisher, Jr. Vice President Age 55 Elected in 1989. Served as Vice President of Customer Operations since 1996.
P. Bernard Jacob Vice President Age 49 Elected in 2003. Served as Vice President of External Affairs and Corporate Services since 2003. Previously served as Director of IR Security and Program Management at SCS from 2002 to 2003 and Manager of Telecommunications Strategy at SCS from 1998 to 2002.
Ronnie R. Labrato Vice President, Chief Financial Officer and Comptroller Age 50 Elected in 2000. Previously served as Comptroller and Chief Financial Officer from 2000 to 2001 and Controller from 1992 to 2000.
Gene L. Ussery, Jr. Vice President Age 54 Elected in 2002. Served as Vice President of Power Generation since May 2002. Also serves at Mississippi Power as Vice President of Power Generation and Delivery from September 2000 to present. Previously served as Northern Cluster Manager at Georgia Power for Plants Hammond, Bowen and McDonough-Atkinson from July 2000 to September 2000; and Manager of Plant Bowen at Georgia Power from 1997 to 2000.
The officers of Gulf Power were elected for a term running from the last annual meeting of the directors (July 24, 2003) for one year until the next annual meeting or until their successors are elected and have 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, 2003.
Michael D. Garrett (1) President, Chief Executive Officer and Director Age 54 Elected in 2001. Previously served as Executive Vice President - Customer Service of Alabama Power from January 2000 to May 2001; Executive Vice President of External Affairs of Alabama Power from March 1998 to January 2000.
Anthony J. Topazi (2) President, Chief Executive Officer and Director Age 53 Elected in 2003. Served as Senior Vice President of Southern Power from November 2002 to December 2003 and Vice President of SCS from December 1999 to December 2003. Previously served as Vice President of Southern Power from March 2001 until November 2002 and Vice President of Alabama Power from March 1991 to December 1999.
Bobby J. Kerley Vice President Age 50 Elected in 2003. Served as Vice President of Customer Services and Retail Marketing since December 2003. Previously served at Alabama Power as Division Vice President - Southeast Division Office from April 2001 to December 2003; Division Manager - Operations, Birmingham Division Office from January 2001 to April 2001; Transmission Lines Manager, Corporate Headquarters from March 1997 to January 2001.
Don E. Mason Vice President Age 62 Elected in 1983. Served as Vice President of External Affairs and Corporate Services since 1983.
Michael W. Southern Vice President, Treasurer and Chief Financial Officer Age 51 Elected in 1995. Previously served as Vice President, Secretary, Treasurer and Chief Financial Officer from 1995 to 2001.
Gene L. Ussery, Jr. Vice President Age 54 Elected in 2000. Served as Vice President of Power Generation and Delivery since September 2000 and Vice President of Power Generation at Gulf Power since May 2002. Previously served as Northern Cluster Manager at Georgia Power for Plants Hammond, Bowen and McDonough-Atkinson from July 2000 to September 2000; and Manager of Plant Bowen at Georgia Power from 1997 to 2000.
(1) Mr. Garrett was elected President and Director of Georgia Power effective January 1, 2004. In addition, he will become Chief Executive Officer of Georgia Power effective April 2004.
(2) Mr. Topazi was elected President, Chief Executive Officer and Director of Mississippi Power effective January 1, 2004.
The officers of Mississippi Power were elected for a term running from the last annual meeting of the directors (April 23, 2003) for one year until the next annual meeting or until their successors are elected and have qualified, except for Mr. Kerley and Mr. Topazi whose elections were effective November 14, 2003 and January 1, 2004, respectively.
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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) The common stock of Southern Company is listed and traded on the New York Stock Exchange. The stock is also traded on regional exchanges across the United States. High and low stock prices, per the New York Stock Exchange Composite Tape, during each quarter for the past two years were as follows:
------------------------------------------------------- High Low -------------- -------------- First Quarter $30.81 $27.71 Second Quarter 31.81 27.94 Third Quarter 30.53 27.76 Fourth Quarter 30.40 28.65
First Quarter $26.78 $24.49 Second Quarter 28.39 25.65 Third Quarter 29.02 23.89 Fourth Quarter 30.85 25.17
-------------------------------------------------------
There is no market for the other registrants' common stock, all of which is owned by Southern Company. On February 25, 2004, the closing price of Southern Company's common stock was $29.79.
(b) Number of Southern Company's common stockholders of record at December 31, 2003: 134,068
Each of the other registrants have one common stockholder, Southern Company.
(c) 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 retail operating companies to their stockholder(s) for the past two years were as follows:
--------------------------------------------------------- Registrant Quarter 2003 2002 --------------------------------------------------------- (in thousands)
Southern Company First $ 245,745 $ 234,272 Second 247,324 236,154 Third 255,042 242,850 Fourth 256,334 244,309
Alabama Power First 107,550 107,750 Second 107,550 107,750 Third 107,550 107,750 Fourth 107,550 107,750
Georgia Power First 141,450 135,725 Second 141,450 135,725 Third 141,450 135,725 Fourth 141,450 135,725
Gulf Power First 17,550 16,375 Second 17,550 16,375 Third 17,550 16,375 Fourth 17,550 16,375
Mississippi First 16,500 15,875 Power Second 16,500 15,875 Third 16,500 15,875 Fourth 16,500 15,875
Savannah Electric First 5,750 5,675 Second 5,750 5,675 Third 5,750 5,675 Fourth 5,750 5,675 ---------------------------------------------------------
Southern Power did not pay a dividend in 2002, but paid a $77 million dividend to Southern Company in the third quarter of 2003.
The dividend paid per share by Southern Company was 33.5(cents) first two quarters of 2002 and 34.25(cents) for the two remaining quarters in 2002. The dividend paid on Southern Company's common stock for the first and second quarters of 2003 was 34.25(cents) per share and for the third and fourth quarters of 2003 was 35(cents) per share.
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The amount of dividends on their common stock that may be paid by the subsidiary registrants (except Alabama Power, Georgia Power and Southern Power) is restricted in accordance with their respective first mortgage bond indenture. See Note 8 of Southern Company and Note 6 of Gulf Power, Mississippi Power and Savannah Electric to the financial statements in Item 8 herein for additional information regarding these restrictions. The amounts of earnings retained in the business and the amounts restricted against the payment of cash dividends on common stock at December 31, 2003 were as follows:
---------------------------------------------------------- Retained Restricted Earnings Amount ------------------ ------------- (in millions) Alabama Power $ 1,292 $ - Georgia Power 2,010 - Gulf Power 161 127 Mississippi Power 203 118 Savannah Electric 110 68 Southern Power 218 - Consolidated 5,343 $313 ----------------------------------------------------------
Item 6.
Item 6. SELECTED FINANCIAL DATA
Southern Company. Reference is made to information under the heading "Selected Consolidated Financial and Operating Data," contained herein at pages II-62 and II-63.
Alabama Power. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-106 and II-107.
Georgia Power. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-155 and II-156.
Gulf Power. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-196 and II-197.
Mississippi Power. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-241 and II-242.
Savannah Electric. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-282 and II-283.
Southern Power. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at page II-313.
Item 7.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Southern Company. Reference is made to information under the heading "Management's Discussion and Analysis of Results of Operations and Financial Condition," contained herein at pages II-10 through II-28.
Alabama Power. Reference is made to information under the heading "Management's Discussion and Analysis of Results of Operations and Financial Condition," contained herein at pages II-67 through II-82.
Georgia Power. Reference is made to information under the heading "Management's Discussion and Analysis of Results of Operations and Financial Condition," contained herein at pages II-111 through II-127.
Gulf Power. Reference is made to information under the heading "Management's Discussion and Analysis of Results of Operations and Financial Condition," contained herein at pages II-160 through II-174.
Mississippi Power. Reference is made to information under the heading "Management's Discussion and Analysis of Results of Operations and Financial Condition," contained herein at pages II-201 through II-217.
Savannah Electric. Reference is made to information under the heading "Management's Discussion and Analysis of Results of Operations and Financial Condition," contained herein at pages II-246 through II-260.
Southern Power. Reference is made to information under the heading "Management's Discussion and Analysis of Results of Operations and Financial Condition," contained herein at pages II-287 through II-298.
II-2
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Reference is made to information in each of the registrants' "Management's Discussion and Analysis - Financial Condition And Liquidity - Market Price Risk" in Item 7 herein and to Notes 1 and 6 to each of the registrants' financial statements in Item 8
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Previously reported by each registrant, except for Southern Power, in separate Current Reports on Form 8-K dated March 28, 2002.
II-5
Item 9A.
Item 9A. CONTROLS AND PROCEDURES
(a) Evaluation of disclosure controls and procedures.
As of the end of the period covered by this annual report, Southern Company, the retail operating companies and Southern Power conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and the 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 those 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 each company (including its consolidated subsidiaries) required to be included in periodic filings with the SEC.
(b) Changes in internal controls.
There have been no changes in Southern Company's, the retail operating companies' or Southern Power's internal controls 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 of 2003 that have materially affected or are reasonably likely to materially affect, Southern Company's, the retail operating companies' or Southern Power's internal controls over financial reporting.
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PAGE>
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
II-7
MANAGEMENT'S REPORT Southern Company and Subsidiary Companies 2003 Annual Report
The management of Southern Company has prepared -- and is responsible for -- the consolidated financial statements and related information included in this report. These statements were prepared in accordance with accounting principles generally accepted in the United States and necessarily include amounts that are based on the best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements.
The company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that the accounting records reflect only authorized transactions of the company. Limitations exist in any system of internal controls, however, based on a recognition that the cost of the system should not exceed its benefits. The company believes its system of internal accounting controls maintains an appropriate cost/benefit relationship.
The company's internal accounting controls are evaluated on an ongoing basis by the company's internal audit staff. The company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements.
The audit committee of the board of directors, composed of four independent directors, provides a broad overview of management's financial reporting and control functions. Periodically, this committee meets with management, the internal auditors, and the independent public accountants to ensure that these groups are fulfilling their obligations and to discuss auditing, internal controls, and financial reporting matters. The internal auditors and independent public accountants have access to the members of the audit committee at any time.
Management believes that its policies and procedures provide reasonable assurance that the company's operations are conducted according to a high standard of business ethics.
In management's opinion, the consolidated financial statements present fairly, in all material respects, the financial position, results of operations, and cash flows of Southern Company and its subsidiary companies in conformity with accounting principles generally accepted in the United States.
/s/H. Allen Franklin H. Allen Franklin Chairman, President, and Chief Executive Officer
/s/Thomas A. Fanning Thomas A. Fanning Executive Vice President, Chief Financial Officer, and Treasurer March 1, 2004
II-8
INDEPENDENT AUDITORS' REPORT
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 as of December 31, 2003 and 2002, and the related consolidated statements of income, comprehensive income, common stockholders' equity, and cash flows for the years then ended. These financial statements are the responsibility of Southern Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The consolidated financial statements of Southern Company and Subsidiary Companies for the year ended December 31, 2001, were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those consolidated financial statements and included an explanatory paragraph that described a change in the method of accounting for derivative instruments and hedging activities in their report dated February 13, 2002.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, the consolidated financial statements (pages II-29 to II-61) present fairly, in all material respects, the financial position of Southern Company and Subsidiary Companies at December 31, 2003 and 2002, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the consolidated financial statements, in 2003 Southern Company changed its method of accounting for asset retirement obligations.
/s/Deloitte & Touche LLP Atlanta, Georgia March 1, 2004
THE FOLLOWING REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH THE COMPANY'S 2001 ANNUAL REPORT ON FORM 10-K AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP. SEE EXHIBIT 23(a)2 FOR ADDITIONAL INFORMATION.
To Southern Company:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Southern Company (a Delaware corporation) and subsidiary companies as of December 31, 2001 and 2000, 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, 2001. 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 auditing standards generally accepted in the 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, the consolidated financial statements (pages II-19 to II-42) referred to above present fairly, in all material respects, the financial position of Southern Company and subsidiary companies as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
As explained in Note 1 to the financial statements, effective January 1, 2001, Southern Company changed its method of accounting for derivative instruments and hedging activities.
/s/Arthur Andersen LLP Atlanta, Georgia February 13, 2002
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Southern Company and Subsidiary Companies 2003 Annual Report
OVERVIEW OF CONSOLIDATED EARNINGS - --------------------------------- AND BUSINESS ACTIVITIES - -----------------------
Earnings
Southern Company's financial performance in 2003 was very strong and one of the best in the electric utility industry. This performance reflected our goal to deliver solid results to stockholders and to provide low-cost energy to more than 4 million customers. Net income of $1.5 billion increased 11.8 percent over income reported in 2002. Net income from continuing operations was $1.3 billion in 2002 and $1.1 billion in 2001. This was a 17.6 percent and 12.7 percent increase in 2002 and 2001, respectively. Basic earnings per share from continuing operations in 2003 were $2.03 per share, $1.86 in 2002, and $1.62 in 2001. Dilution -- which factors in additional shares related to stock options -- decreased earnings per share in 2003, 2002, and 2001 by 1 cent each year.
On April 2, 2001, Southern Company completed the spin off of its remaining 80.1 percent ownership of Mirant Corporation (Mirant) in a tax-free transaction. As a result of the spin off, Southern Company's 2001 financial statements and related information reflect Mirant as discontinued operations.
Dividends
Southern Company has paid dividends on its common stock since 1948. Dividends paid per share on common stock were $1.385 in 2003, $1.355 in 2002, and $1.34 in 2001. In January 2004, Southern Company declared a quarterly dividend of 35 cents per share. This is the 225th consecutive quarter that Southern Company has paid a dividend equal to or higher than the previous quarter. The company's goal for the dividend payout ratio is 70 percent.
Southern Company Business Activities
Discussion of the results of operations is focused on Southern Company's primary business of electricity sales in the Southeast by the retail operating companies - -- Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric -- and Southern Power. Southern Power is an electric wholesale generation subsidiary with market-based rate authority. Southern Company's other business activities include investments in synthetic fuels and leveraged lease projects, telecommunications, energy-related services, natural gas marketing, and the parent holding company.
Several factors affect the opportunities, challenges, and risk of Southern Company's primary business of selling electricity. These factors include the retail operating companies' ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stricter environmental standards. 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. 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.
RESULTS OF OPERATIONS - ---------------------
Electricity Businesses
Southern Company's electric utilities generate and sell electricity to retail and wholesale customers in the Southeast. A condensed income statement for the six companies that make up the electricity business is as follows:
Increase (Decrease) Amount From Prior Year ---------------------------------- 2003 2003 2002 2001 - --------------------------------------------------------------- (in millions) Operating revenues $10,747 $541 $ 300 $ 46 - --------------------------------------------------------------- Fuel 2,998 212 209 13 Purchased power 473 24 (269) 41 Other operation and maintenance 2,858 107 262 19 Depreciation and amortization 972 (16) (155) 9 Taxes other than income taxes 584 29 22 1 - --------------------------------------------------------------- Total operating expenses 7,885 356 69 83 - --------------------------------------------------------------- Operating income 2,862 185 231 (37) Other income, net 2 20 (32) 51 Interest expenses and other, net 595 9 (24) (25) Income taxes 845 68 76 (1) - --------------------------------------------------------------- Net income $ 1,424 $128 $ 147 $ 40 ===============================================================
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2003 Annual Report
Revenues
Details of electric operating revenues are as follows:
2003 2002 2001 - ----------------------------------------------------------------- (in millions) Retail -- prior year $ 8,728 $ 8,440 $8,600 Change in -- Base rates 75 33 23 Sales growth 104 98 61 Weather (135) 158 (177) Fuel cost recovery and other 103 (1) (67) - ----------------------------------------------------------------- Retail -- current year 8,875 8,728 8,440 - ----------------------------------------------------------------- Sales for resale -- Within service area 403 393 338 Outside service area 955 775 836 - ----------------------------------------------------------------- Total sales for resale 1,358 1,168 1,174 - ----------------------------------------------------------------- Other electric operating revenues 514 310 292 - ----------------------------------------------------------------- Electric operating revenues $10,747 $10,206 $9,906 ================================================================= Percent change 5.3% 3.0% 0.5% - -----------------------------------------------------------------
Retail revenues increased $147 million in 2003 and $288 million in 2002 and declined $160 million in 2001. The significant factors driving these changes are shown in the table above.
Electric rates -- for the retail operating companies -- include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased energy costs, and certain other costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses -- including the fuel component of purchased energy -- and do not affect net income.
Sales for resale revenues within the service area for 2003 increased $10 million, which reflected increased customer growth offset by milder weather, compared with sales in 2002. Revenues from sales for resale within the service area in 2002 increased $55 million as a result of above normal weather. The same sales for resale category in 2001 was $338 million, down 10.2 percent from the prior year. This sharp decline resulted primarily from the mild weather experienced in the Southeast during 2001.
Revenues from energy sales for resale outside the service area increased $180 million as a result of new contracts, higher gas prices, and milder weather. The new contracts reflected some 2,400 megawatts of new generating capacity being placed into service in 2003. As a result of mild weather, more coal-fired generation was available for sale to utilities outside the service area. In general, sales for resale outside the service area can be significantly influenced by weather, which affects both customer demand and generating availability for these type sales. Neighboring utilities that depend heavily on gas-fired generation purchase larger amounts of power as natural gas prices increase. These factors contribute to the large fluctuations in sales from year to year.
In 2002, revenues from energy sales for resale outside the service area were down 7.3 percent after having increased 39 percent in 2001. The decline in 2002 resulted from the expiration of certain short-term energy sales contracts in effect in 2001. Revenues from outside the service area have increased $355 million since 2000 as a result of growth driven by new longer-term contracts. As Southern Company increases its competitive wholesale generation business, sales for resale outside the service area should reflect steady increases over the near term. Recent wholesale contracts with market-based capacity and energy rates have shorter contract periods than the traditional cost-based contracts entered into in the 1980s. The older contracts are principally unit power sales to Florida utilities. Under the unit power sales contracts, capacity revenues reflect the recovery of fixed costs and a return on investment, and energy is generally sold at variable cost. The capacity and energy components of the unit power contracts and other long-term contracts were as follows:
2003 2002 2001 ---------------------------------------------------------------- (in millions) Unit power -- Capacity $182 $175 $170 Energy 211 198 201 Other long term -- Capacity 111 100 112 Energy 451 306 353 - ---------------------------------------------------------------- Total $955 $779 $836 ================================================================
Capacity revenues for unit power contracts in 2003, 2002, and 2001 each varied slightly compared with the prior year as a result of adjustments and true-ups related to contractual pricing. No significant declines in the amount of capacity are scheduled until the termination of the contracts in 2010.
In May 2003, Mississippi Power and Southern Power entered into agreements with Dynegy, Inc. (Dynegy) that resolved and terminated in 2003 all outstanding
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2003 Annual Report
matters related to capacity sales contracts with subsidiaries of Dynegy. The termination payments from Dynegy resulted in an increase in other electric revenues of $135 million for the year 2003.
Energy Sales
Changes in revenues are influenced heavily by the volume of energy sold each year. Kilowatt-hour sales for 2003 and the percent change by year were as follows:
Amount Percent Change (billions of ------- -------------------------- kilowatt-hours) 2003 2003 2002 2001 - -------------------------------------------------------------- Residential 47.8 (1.9)% 9.5% (3.6)% Commercial 48.4 0.3 2.8 1.5 Industrial 54.4 1.0 1.8 (6.8) Other 1.0 (0.2) 2.3 0.7 - -------------------------------------------------------------- Total retail 151.6 (0.2) 4.5 (3.2) Sales for resale -- Within service area 9.4 (11.2) 12.9 (2.0) Outside service area 31.1 41.7 2.7 24.4 - -------------------------------------------------------------- Total 192.1 4.2 4.7 (0.5) ==============================================================
Residential energy sales in 2003 reflected a decrease in customer demand as a result of very mild weather partially offset by an increase of 1.6 percent in new customers. Commercial sales continued to show steady growth while industrial sales increased somewhat over the depressed results of recent years. In 2002, the rate of growth in total retail energy sales was very strong. Residential energy sales reflected an increase as a result of hotter-than-normal summer weather and a 1.6 percent increase in customers served. In 2001, retail energy sales registered a 3.2 percent decline. This was the first decrease since 1982 and was driven by extremely mild weather and the sluggish economy, which severely impacted industrial sales. Energy sales to retail customers are projected to increase at an average annual rate of 1.6 percent during the period 2004 through 2014.
Sales to customers outside the service area under contracts and opportunity sales increased by 8.0 billion, 1.0 billion, and 3.9 billion kilowatt-hours in 2003, 2002, and 2001, respectively. In 2003, these sales reflected the expansion of the competitive wholesale contract business discussed earlier, as well as increased availability of coal-fired generation resulting from weather-related lower retail demand coupled with higher natural gas prices, which increase the wholesale market price related to opportunity sales. Unit power energy sales increased 4.0 percent in 2003, decreased 3.3 percent in 2002, and increased 2.7 percent in 2001. Fluctuations in oil and natural gas prices, which are the primary fuel sources for unit power sales customers, influence changes in sales. However, these fluctuations in energy sales under long-term contracts have minimal effect on earnings because the energy is generally sold at variable cost.
Expenses
Electric operating expenses in 2003 were $7.9 billion, an increase of $356 million over 2002 expenses. Electricity production costs exceeded last year's cost by $210 million as a result of increased electricity sales and a 6.8 percent increase in the average unit cost of fuel. Non-production electricity operation and maintenance costs also increased by $159 million in 2003. This increase in expenses was primarily driven by additional administrative and general expenses of $45 million, customer service expenses of $15 million, and a $60 million regulatory expense related to Plant Daniel. For more information regarding this regulatory expense, see Note 3 to the financial statements under "Mississippi Power Regulatory Filing." Taxes other than income taxes increased $29 million in 2003 as a result of new facilities with a higher tax basis for property taxes. Depreciation and amortization declined by $16 million in 2003, primarily as a result of Georgia Power's 2001 rate order to recognize certain purchased power costs evenly over a three-year period. This amortization reduced depreciation expense by $49 million in 2003. This expense was partially offset by a higher depreciable plant basis. For more information regarding the 2001 rate action, see Note 3 to the financial statements under "Georgia Power Retail Rate Orders."
In 2002, electric operating expenses were $7.5 billion, an increase of $69 million over 2001 expenses. Electricity production costs exceeded 2001 cost by $88 million as a result of increased electricity sales. Non-production electricity operation and maintenance costs also increased in 2002 by $109 million. Taxes other than income taxes increased $22 million in 2002. Depreciation and amortization declined by $155 million in 2002 primarily as a result of Georgia Power's 2001 rate order to reverse and amortize over three years $333 million that had been previously expensed related to accelerated depreciation under a previous rate order. This amortization reduced depreciation expense in 2002 by $111 million.
Electric operating expenses in 2001 increased only $83 million compared with the prior year. The moderate increase reflected flat energy sales and tighter cost-containment measures, which included lower staffing levels and reductions in certain non-critical expenses. The costs to produce electricity in 2001 increased $96 million. However, non-production operation and maintenance expenses declined by $23 million.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2003 Annual Report
Fuel costs constitute the single largest expense for the six 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. The amount and sources of generation, the average cost of fuel per net kilowatt-hour generated, and the average cost of purchased power were as follows:
2003 2002 2001 - --------------------------------------------------------------- Total generation (billions of kilowatt-hours) 189 183 174 Sources of generation (percent) -- Coal 71 69 72 Nuclear 16 16 16 Gas 9 12 9 Hydro 4 3 3 Average cost of fuel per net kilowatt-hour generated (cents) 1.72 1.61 1.56 Average cost of purchased power per net kilowatt-hour (cents) 3.82 4.17 6.10 - ---------------------------------------------------------------
Fuel and purchased power costs to produce electricity were $3.5 billion in 2003, an increase of $295 million or 7.4 percent above the prior year costs. This increase was attributed to higher unit fuel cost and increased customer demand. The additional demand was met by generating 6 billion and purchasing 1.6 billion more kilowatt-hours than in 2002.
In 2002, fuel and purchased power costs to produce electricity were $3.23 billion, a decrease of $79 million or 2.4 percent below the prior year costs. An additional 8.9 billion kilowatt-hours were generated in 2002, at a slightly higher average cost; however, this lowered requirements to purchase more expensive electricity from other utilities. Fuel and purchased power costs in 2001 were $3.3 billion, an increase of $54 million. Continued efforts to control energy costs, combined with additional efficient gas-fired generating units, helped to hold the increase in fuel expense to $13 million in 2001.
Total interest charges and other financing costs in 2003 increased by $19 million as a result of Southern Power issuing $575 million of senior notes in both 2003 and 2002 to finance new generating facilities. This increase offset the reduction in interest costs related to the retail operating companies refinancing higher-cost debt in 2003. Total interest charges and other financing costs declined by $24 million in 2002 and $25 million in 2001 as a result of much lower interest rates on short-term debt and continued refinancing of higher-cost long-term securities.
Other Business Activities
Southern Company's other business activities include the parent company -- which does not allocate operating expenses to business units -- investments in synthetic fuels and leveraged lease projects, telecommunications, energy services, and natural gas marketing. These businesses are classified in general categories and may comprise one or more of the following subsidiaries. Southern Company Holdings invests in synthetic fuels and leveraged lease projects that receive tax benefits, which contribute significantly to the economic results of these investments; Southern LINC provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast; Southern Telecom provides fiber optics services in the Southeast; and Southern Company Energy Solutions provides energy services, including energy efficiency improvements, for large commercial and industrial customers, municipalities, and government entities. Southern Company GAS is a retail gas marketer serving Georgia.
A condensed income statement for Southern Company's other business activities is shown below:
Increase (Decrease) Amount From Prior Year ------- ----------------------- 2003 2003 2002 2001 - --------------------------------------------------------------- (in millions) Operating revenues $ 504 $161 $ 94 $ 43 - --------------------------------------------------------------- Operation and maintenance 414 101 41 29 Depreciation and amortization 55 (4) 30 (7) Taxes other than income taxes 2 - - (2) - --------------------------------------------------------------- Total operating expenses 471 97 71 20 - --------------------------------------------------------------- Operating income 33 64 23 23 Equity in losses of unconsolidated subsidiaries (185) (30) (102) (31) Leveraged lease income 66 8 (1) (2) Other income, net 7 8 (11) 5 Interest expenses 104 6 (37) (62) Income taxes (233) 16 (105) (29) - --------------------------------------------------------------- Net income $ 50 $ 28 $ 51 $ 86 ===============================================================
Southern Company's non-regulated business investments continued to provide financial returns consistent with the company's earnings goals. Non-regulated revenues increased $161 million in 2003. Southern Company GAS began operations
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2003 Annual Report
in August 2002 and recorded revenues of $168 million in 2003 and $68 million in 2002. Southern LINC's revenues increased $8 million, $32 million, and $12 million in 2003, 2002, and 2001, respectively, as a result of increased wireless subscribers. Revenues from a subsidiary formed in April 2001 that provides services related to synthetic fuel products were $93 million in 2003, increasing by $37 million and $26 million in 2003 and 2002, respectively, as a result of increased production at the facilities. The majority of these revenues relate to transportation services that are billed at cost and, therefore, have no effect on net income.
The increases in 2003 and 2002 operating and maintenance expenses were primarily driven by Southern Company GAS' increases in operating expenses of $120 million and $60 million, respectively. These increases reflect only a partial year of operation in 2002 for Southern Company GAS. Natural gas purchases represent their primary operating expense. Also, the average cost of natural gas per decatherm increased 24 percent in 2003. These increases were partially offset by intersegment eliminations related to synthetic fuels being sold to the retail operating companies. See Note 1 to the financial statements under "Synthetic Fuel Tax Credits" for additional information. In 2002, expenses increased $19 million for Southern LINC as a result of their additional subscribers, and expenses for synthetic fuel product services increased by $30 million as a result of increased production. In 2001, operation and maintenance expenses increased $37 million as a result of a subsidiary formed in April 2001 to produce synthetic fuel. This increase was partially offset by a reduction in expenses related to a private security subsidiary that was sold in late 2000.
The changes in depreciation expense in 2002 reflects a $16 million charge at Southern Company Energy Solutions related to the impairment of assets under contracts to certain customers, as well as the impact of property additions at Southern LINC. The 2001 decreases relate to investment write offs in 2000.
The increases in equity in losses of unconsolidated subsidiaries in 2002 and 2001 reflect the results of additional investments in synthetic fuel partnerships that produce operating losses. These partnerships also claim federal income tax credits that offset these operating losses and make the projects profitable. These credits totaled $120 million in 2003, $108 million in 2002, and $71 million in 2001.
The increase in other income in 2003 reflected a $15 million gain for a Southern Telecom contract settlement during the year. This gain was offset by an increase of $7 million in charitable contributions above the amount in 2002 made by the parent holding company.
Interest expenses for 2003 increased $18 million for the redemption of $430 million of preferred securities. This increase was partially offset by less short-term debt outstanding at the parent company. Interest expense charges in 2002 and 2001 reflect lower interest rates and less amounts of debt outstanding for the parent company.
Effects of Inflation
The retail operating companies and Southern Power are subject to rate regulation and long-term contracts, respectively, that are based on the recovery of historical costs. In addition, the income tax laws are also based on historical costs. Therefore, inflation creates an economic loss because the company is recovering its costs of investments in dollars that have less purchasing power. 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 and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed in the retail operating companies' approved electric rates.
Future Earnings Potential
General
The results of continuing 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. These factors affect the opportunities, challenges, and risk of Southern Company's primary business of selling electricity. These factors include the retail operating companies' ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stricter environmental standards. 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. 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2003 Annual Report
customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the service area.
Industry Restructuring
The retail operating companies operate as vertically integrated companies providing electricity to customers within the service area of the southeastern United States. Prices for electricity provided to retail customers are set by state public service commissions under cost-based regulatory principles. Retail rates and earnings are reviewed and adjusted periodically within certain limitations based on earned return on equity. See Note 3 to the financial statements for additional information about these and other regulatory matters.
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 Policy Act of 1992 (Energy Act). The Energy Act allowed independent power producers to access a utility's transmission network and sell electricity to other utilities.
Although the Energy Act does not provide for retail customer access, it was a major catalyst for restructuring and consolidations that took place within the utility industry. Numerous federal and state initiatives that promote wholesale and retail competition are in varying stages. Among other things, these initiatives allow retail customers in some states to choose their electricity provider. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While various restructuring and competition initiatives have been discussed in Alabama, Florida, Georgia, and Mississippi, none have been enacted. Enactment could require numerous issues to be resolved, including significant ones relating to recovery of any stranded investments, full cost recovery of energy produced, and other issues related to the energy crisis that occurred in California, as well as the August 2003 power outage in the Northeast. As a result of these issues, many states, including those in Southern Company's retail service area, have either discontinued or delayed consideration of initiatives involving retail deregulation.
Since 2001, merchant energy companies and traditional electric utilities with significant energy marketing and trading activities have come under severe financial pressures. Many of these companies have completely exited or drastically reduced all energy marketing and trading activities and sold foreign and domestic electric infrastructure assets. Southern Company has not experienced any material adverse financial impact regarding its limited energy trading operations and recent generating capacity additions. In general, Southern Company only constructs new generating capacity 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.
Southern Company continues to maintain and expand its wholesale energy business in the Southeast. In 2001, Southern Company formed Southern Power to construct, own, and manage wholesale generating assets in the Southeast. Southern Power is the primary growth engine for Southern Company's competitive wholesale energy business. By the end of 2005, Southern Power plans to have approximately 6,000 megawatts of available generating capacity in commercial operation. At December 31, 2003, approximately 4,800 megawatts were in commercial operation.
Continuing to be a low-cost producer could provide opportunities to increase the size and profitability of the electricity sales business in markets that evolve with changing regulation and competition. Conversely, future regulatory changes could adversely affect the company's growth, and if Southern Company's electric utilities do not remain low-cost producers and provide quality service, then energy sales growth could be limited, and this could significantly erode earnings.
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, internal restructuring, disposition of certain assets, 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 and financial condition of Southern Company.
Environmental Matters
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, and alleged that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act at five coal-fired
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2003 Annual Report
generating facilities. Through subsequent amendments and other legal procedures, the EPA added Savannah Electric as a defendant to the original action. The EPA filed a separate action against Alabama Power after it was dismissed from the original action. As of the date of this report, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power, Georgia Power, and Savannah Electric. 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 actions against Alabama Power, Georgia Power, and Savannah Electric have been stayed since the spring of 2001 during the appeal of a very similar NSR action against the Tennessee Valley Authority before the U.S. Court of Appeals for the Eleventh Circuit. The Eleventh Circuit appeal was decided on September 16, 2003, and on February 13, 2004, the EPA petitioned the U.S. Supreme Court to review the Eleventh Circuit's decision. The EPA also filed a motion to lift the stay in the action against Alabama Power. At this time, no party to the Georgia Power and Savannah Electric action, which was administratively closed two years ago, has asked the court to reopen that case. See Note 3 to the financial statements under "New Source Review Actions" for additional information.
In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. The December 2002 revisions included changes to the regulatory exclusions and the methods of calculating emissions increases. The October 2003 regulations clarified the scope of the existing Routine Maintenance, Repair, and Replacement exclusion. A coalition of states and environmental organizations filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. On December 24, 2003, the court of appeals granted a stay of the October 2003 revisions pending its review of the rules and ordered that its review be conducted on an expedited basis. In January 2004, the Bush Administration announced that it would continue to enforce the existing rules until the courts resolve legal challenges to the EPA's revised NSR regulations. In any event, the final regulations must be adopted by the states in the company's service area in order to apply to facilities in the Southern Company system. The effect of these final regulations and the related legal challenges cannot be determined at this time.
Southern Company believes that its retail operating companies complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome in any one of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
Plant Wansley Environmental Litigation
On December 30, 2002, the Sierra Club, Physicians for Social Responsibility, Georgia ForestWatch, and one individual filed a civil suit in the U.S. District Court in Georgia against Georgia Power for alleged violations of the Clean Air Act at four of the units at Plant Wansley. The civil action requests injunctive and declaratory relief, civil penalties, a supplemental environmental project, and attorneys' fees. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. The case is currently scheduled for trial during the summer of 2004. See Note 3 to the financial statements under "Plant Wansley Environmental Litigation" for additional information.
While the company believes that it has complied with applicable laws and regulations, an adverse outcome could require payment of substantial penalties. The final outcome of this matter cannot now be determined.
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 environmental requirements will involve significant costs - -- both capital and operating -- a major portion of which is expected to be recovered through existing ratemaking provisions. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under "Capital Requirements and Contractual Obligations." There is no assurance, however, that all such costs will, in fact, be recovered.
Compliance with the federal Clean Air Act and resulting regulations has been and will continue to be a significant focus for the company. The Title IV acid rain provisions of the Clean Air Act, for example, required significant reductions in sulfur dioxide and nitrogen oxide emissions. Title IV compliance was effective in 2000 and associated construction expenditures totaled approximately $400 million. Some of these expenditures also assisted the company in complying with nitrogen oxide emission reduction requirements under Title I of the Clean Air Act, which were designed to address one-hour ozone
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2003 Annual Report
nonattainment problems in Atlanta, Georgia and Birmingham, Alabama. The states of Alabama and Georgia adopted regulations that required additional nitrogen oxide emission reductions from May through September of each year at plants in and/or near those nonattainment areas. Seven generating plants in the Atlanta area and two plants in the Birmingham area are currently subject to those requirements, the most recent of which went into effect in 2003. Construction expenditures for compliance with the nitrogen oxide emission reduction requirements are estimated to be approximately $950 million, of which $17 million remains to be spent.
On September 26, 2003, the EPA published a final rule, effective January 1, 2004, reclassifying the Atlanta area from a "serious" to a "severe" nonattainment area for the one-hour ozone air quality standard under Title I of the Clean Air Act. The attainment deadline is to be as expeditious as practicable but not later than November 15, 2005. If the Atlanta area fails to attain the one-hour ozone standard by the deadline, all major sources of nitrogen oxides and volatile organic compounds located in the nonattainment area, including Georgia Power's plants McDonough and Yates, could be subject to payment of annual emissions fees for nitrogen oxides emitted above 80 percent of the baseline period. The baseline period is expected to be the calendar year 2005. Based on average emissions at these units over the past three years, such fees could reach $23 million annually. The final outcome of this matter will depend on the baseline period selected and the development, approval, and implementation of applicable regulations, including new regulations for the eight-hour ozone air quality standard.
In 2002, Gulf Power entered into an agreement with the state of Florida to install additional controls on certain units and to retire three older units at a plant near Pensacola to help ensure attainment of the ozone standard in the area. The conditions of the agreement will be fully implemented by 2005 at a cost of approximately $133 million, of which $100 million remains to be spent. Gulf Power's costs have been approved under its environmental cost recovery clause.
To help ozone nonattainment areas attain the one-hour ozone standard, the EPA issued regional nitrogen oxide reduction rules in 1998. Those rules required 21 states, including Alabama and Georgia, to reduce and cap nitrogen oxide emissions from power plants and other large industrial sources. Affected sources, including five of the company's coal-fired plants in Alabama, must comply with the reduction requirements by May 31, 2004. Additional construction expenditures for compliance with these rules are currently estimated at approximately $360 million, of which $330 million remains to be spent. As a result of litigation challenging the rule, the courts required the EPA to complete a separate rulemaking before the requirements can be applied in Georgia. The final EPA rules have not been issued in Georgia.
In July 1997, the EPA revised the national ambient air quality standards for ozone and particulate matter. These revisions made the standards significantly more stringent. In the subsequent litigation of these standards, the U.S. Supreme Court found the EPA's implementation program for the new eight-hour ozone standard unlawful and remanded it to the EPA for further rulemaking. During 2003, the EPA proposed implementation rules designed to address the court's concerns. The EPA plans to designate areas as attainment or nonattainment with the new eight-hour ozone standard in April 2004 and with the new fine particulate matter standard by the end of 2004. These designations will be based on air quality data for 2001 through 2003. Several areas within Southern Company's service area are likely to be designated nonattainment under these standards. State implementation plans (SIPs), including new emission control regulations necessary to bring those areas into attainment, could be required as early as 2007. These SIPs could require reductions in sulfur dioxide emissions and could require further reductions in nitrogen oxide emissions from power plants. If so, reductions could be required sometime after 2007. The impact of any new standards will depend on the development and implementation of applicable regulations and cannot be determined at this time.
In January 2004, the EPA issued a proposed Interstate Air Quality Rule to address interstate transport of ozone and fine particles. This proposed rule would require additional year-round sulfur dioxide and nitrogen oxide emission reductions from power plants in the eastern United States in two phases - in 2010 and 2015. The EPA currently plans to finalize this rule by 2005. If finalized, the rule could modify or supplant other SIP requirements for attainment of the fine particulate matter standard and the eight-hour ozone standard. The impact of this rule on the company will depend upon the specific requirements of the final rule and cannot be determined at this time.
Further reductions in sulfur dioxide and nitrogen oxides could also be required under the EPA's Regional Haze rules. The Regional Haze rules require states to establish Best Available Retrofit Technology (BART) standards for certain sources that contribute to regional haze. The company has a number of plants that could be subject to these rules. The EPA's Regional Haze program calls for states to submit SIPs in 2007. The SIPs must contain emission
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2003 Annual Report
reduction strategies for implementing BART and achieving progress toward the Clean Air Act's visibility improvement goal. In 2002, however, the U.S. Court of Appeals for the District of Columbia Circuit vacated and remanded the BART provisions of the federal Regional Haze rules to the EPA for further rulemaking. The EPA has entered into an agreement that requires proposed revised rules in April 2004 and final rules in 2005. Because new BART rules have not been developed and state visibility assessments for progress are only beginning, it is not possible to determine the effect of these rules on the company at this time.
The EPA's Compliance Assurance Monitoring (CAM) regulations under Title V of the Clean Air Act require that monitoring be performed to ensure compliance with emissions limitations on an ongoing basis. In 2004 and 2005, a number of the company's plants will likely become subject to CAM requirements for at least one pollutant, in most cases particulate matter. The company is in the process of developing CAM plans. Because the plans are still under development, the company cannot determine the costs associated with implementation of the CAM regulations. Actual ongoing monitoring costs are expensed as incurred and are not material for any year presented.
In January 2004, the EPA issued proposed rules regulating mercury emissions from electric utility boilers. The proposal solicits comments on two possible approaches for the new regulations - a Maximum Achievable Control Technology approach and a cap-and-trade approach. Either approach would require significant reductions in mercury emissions from company facilities. The regulations are scheduled to be finalized by the end of 2004, and compliance could be required as early as 2007. Because the regulations have not been finalized, the impact on the company cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent emissions limitations on power plants have been proposed by Congress. Three of these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2003, and the Clean Air Planning Act of 2003, propose to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills also propose to limit emissions of carbon dioxide. The cost impacts of such legislation would depend upon the specific requirements enacted and cannot be determined at this time.
Domestic efforts to limit greenhouse gas emissions have been spurred by international discussions surrounding the Framework Convention on Climate Change and specifically the Kyoto Protocol, which proposes international constraints on the emissions of greenhouse gases. The Bush Administration does not support U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation and has instead announced a new voluntary climate initiative, known as Climate VISION, which seeks an 18 percent reduction by 2012 in the rate of greenhouse gas emissions relative to the dollar value of the U.S. economy. Southern Company is involved in a voluntary electric utility industry sector climate change initiative in partnership with the government. The electric utility sector has pledged to reduce its greenhouse gas intensity 3 percent to 5 percent over the next decade and is in the process of developing a memorandum of understanding with the Department of Energy (DOE) to cover this voluntary program.
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 could incur substantial costs to clean up properties. The subsidiaries 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 subsidiaries 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 "Georgia Power Potentially Responsible Status" for additional information.
Under the Clean Water Act, the EPA has been developing new rules aimed at reducing impingement and entrainment of fish and fish larvae at power plants' cooling water intake structures. On February 16, 2004, the EPA finalized these rules. These rules will require biological studies and, perhaps, retrofits to some intake structures at existing power plants. The impact of these new rules will depend on the results of studies and analyses performed as part of the rules' implementation.
The company is also planning to install cooling towers at some of its facilities to cool water prior to discharge under the Clean Water Act. Cooling towers for two Georgia Power plants near Atlanta are scheduled for completion in 2004 and 2008 at a total estimated cost of $160 million, of which $90 million remains to be spent. Also, Georgia Power is conducting a study of the aquatic environment at another facility to determine if additional controls are necessary.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2003 Annual Report
In addition, under the Clean Water Act, the EPA and state environmental regulatory agencies are developing total maximum daily loads (TMDLs) for certain impaired waters. Establishment of maximum loads by the EPA or state agencies may result in lowering permit limits for various pollutants and a requirement to take additional measures to control non-point source pollution (e.g., storm water runoff) at facilities that discharge into waters for which TMDLs are established. Because the effect on Southern Company will depend on the actual TMDLs and permit limitations established by the implementing agency, it is not possible to determine the effect on the company at this time.
Several major pieces of environmental legislation are periodically considered for reauthorization or amendment by Congress. These 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 possible additional federal or state legislation or regulations related to global climate change, electromagnetic fields, or other environmental and health concerns could also significantly affect Southern Company. The impact of any new legislation, changes to existing legislation, or environmental regulations could affect many areas of Southern Company's operations. The full impact of any such changes cannot, however, be determined at this time.
FERC Matters
Transmission
In December 1999, the Federal Energy Regulatory Commission (FERC) issued its final rule (Order 2000) on Regional Transmission Organizations (RTOs). Order 2000 encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Southern Company worked with a number of utilities in the Southeast to develop a for-profit RTO known as SeTrans. In 2002, the sponsors of SeTrans established a Stakeholder Advisory Committee to provide input into the development of the RTO from other sectors of the electric industry, as well as consumers. During the development of SeTrans, state regulatory authorities expressed concern over certain aspects of the FERC's policies regarding RTOs. In December 2003, the SeTrans sponsors announced that they would suspend work on SeTrans because the regulated utility participants, including Southern Company, had determined that it was highly unlikely to obtain support of both federal and state regulatory authorities. Any impact of the FERC's rule on Southern Company and its subsidiaries will depend on the regulatory reaction to the suspension of SeTrans and future developments, which cannot now be determined.
In July 2002, the FERC issued a notice of proposed rulemaking regarding open access transmission service and standard electricity market design. The proposal, if adopted, would among other things: (1) require transmission assets of jurisdictional utilities to be operated by an independent entity; (2) establish a standard market design; (3) establish a single type of transmission service that applies to all customers; (4) assert jurisdiction over the transmission component of bundled retail service; (5) establish a generation reserve margin; (6) establish bid caps for day ahead and spot energy markets; and (7) revise the FERC policy on the pricing of transmission expansions. Comments on the proposal were submitted by many interested parties, including Southern Company, and the FERC has indicated that it has revised certain aspects of the proposal in response to public comments. Proposed energy legislation would prohibit the FERC from issuing the final rule before October 31, 2006, and from making any final rule effective before December 31, 2006. That legislation has been approved by the House of Representatives but remains pending before the Senate. Passage of the legislation now appears in doubt. It is uncertain whether in the absence of legislation the FERC will move forward with any part or all of the proposed rule. Any impact of this proposal on Southern Company and its subsidiaries will depend on the form in which the final rule may be ultimately adopted. However, Southern Company's financial statements could be adversely affected by changes in the transmission regulatory structure in its regional power market.
Market-Based Rate Authority
Southern Power currently has general authorization from the FERC to sell power to nonaffiliates at market-based prices. In addition, each of the retail operating companies has obtained FERC approval to sell power to nonaffiliates at market-based prices under specific contracts. Southern Power and the retail operating companies also have FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities' applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2003 Annual Report
applied the SMA to several utilities, including Southern Company, and found Southern Company and others to be "pivotal suppliers" in their service areas and ordered the implementation of several mitigation measures. Southern Company and others sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. Southern Company and others submitted comments to the FERC in 2002 regarding these issues. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. Southern Company anticipates that the FERC will address the requests for rehearing in the near future. Regardless of the outcome of the SMA proposal, the FERC retains the ability to modify or withdraw the authorization for any seller to sell at market-based rates, if it determines that the underlying conditions for having such authority are no longer applicable. In that event, Southern Power would be required to obtain FERC approval of rates based on cost of service, which may be lower than those in negotiated market-based rates. The final outcome of this matter will depend on the form in which the SMA test and mitigation measures' rules may be ultimately adopted and cannot be determined at this time.
Purchased Power Agreements (PPAs) by Georgia Power and Savannah Electric for Southern Power's Plant McIntosh capacity were certified by the Georgia Public Service Commission in December 2002 after a competitive bidding process. In April 2003, Southern Power applied for FERC approval of these PPAs. Interveners opposed the FERC's acceptance of the PPAs, alleging that the PPAs do not meet the applicable standards for market-based rates between affiliates. In July 2003, the FERC accepted the PPAs to become effective as scheduled on June 1, 2005, subject to refund, and ordered that hearings be held. For additional information, see Note 3 to the financial statements under "FERC Matters."
Income Tax Matters
Synthetic Fuel Tax Credits
As discussed in Note 3 to the financial statements under "Synthetic Fuel Tax Credits," Southern Company has investments in two entities that produce synthetic fuel and receive tax credits under Section 29 of the tax code. Both entities have received private letter rulings from the Internal Revenue Service (IRS) concluding that significant chemical change occurred based on the procedures and results submitted. From the inception of Southern Company's investment in these entities through December 31, 2003, Southern Company has recognized through income approximately $274 million (net of approximately $37 million reserved) in tax credits related to its share of the synthetic fuel production at these entities. However, if the IRS were to challenge these credits, there could be a significant tax liability due for tax credits previously taken, which could have a significant impact on earnings and cash flows.
Leveraged Lease Transactions
As discussed in Note 1 to the financial statements under "Leveraged Leases," Southern Company participates in four international leveraged lease transactions. Southern Company receives federal income tax deductions for rent, depreciation and amortization, as well as interest on related debt. The IRS has proposed to disallow the tax losses for one of the lease transactions, as discussed in Note 3 to the financial statements under "Leveraged Lease Transactions," resulting in additional taxes and interest of approximately $30 million. Southern Company accounted for this payment as a deposit and filed a refund claim that the IRS has proposed to disallow. If Southern Company is unsuccessful in defending its position, additional taxes and interest would be assessed that could have a material impact on earnings and cash flows. Although the IRS has not proposed any disallowances related to the three other lease transactions, subsequent audits may do so. The final outcome of these matters cannot now be determined.
Other Matters
In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, Southern Company recorded non-cash pension income, before tax, of approximately $99 million, $117 million, and $124 million in 2003, 2002, and 2001, respectively. Future pension income is dependent on several factors including trust earnings and changes to the plan. The decline in pension income is expected to continue and become an expense as early as 2006. Postretirement benefit costs for Southern Company were $101 million, $99 million, and $96 million in 2003, 2002, and 2001, respectively, and are expected to continue to trend upward. A portion of pension income and postretirement benefit costs is capitalized based on construction-related labor charges. For the retail operating companies, pension income or expense 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2003 Annual Report
On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act introduces a prescription drug benefit for Medicare-eligible retirees starting in 2006, as well as a federal subsidy to plan sponsors like Southern Company that provide prescription drug benefits. In accordance with FASB Staff Position No. 106-1, Southern Company has elected to defer recognizing the effects of the Medicare Act for its postretirement plans under FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other than Pension until authoritative guidance on accounting for the federal subsidy is issued or until a significant event occurs that would require remeasurement of the plans' assets and obligations. Southern Company anticipates that the benefits it pays after 2006 will be lower as a result of the Medicare Act; however, the retiree medical obligations and costs reported in Note 2 to the financial statements do not reflect these changes. The final accounting guidance could require changes to previously reported information.
Georgia Power is required to file a general retail rate case in July 2004. The outcome will have a significant impact on future earnings. See Note 3 to the financial statements under "Georgia Power Retail Rate Orders" for additional information.
On May 21, 2003, Mississippi Power and Southern Power entered into agreements with Dynegy that resolved and terminated in 2003 all outstanding matters related to capacity sales contracts with subsidiaries of Dynegy. The termination payments from Dynegy resulted in a one-time gain to Southern Company of approximately $88 million after tax -- $38 million for Mississippi Power and $50 million for Southern Power. As a result of the Dynegy capacity contract terminations, Southern Power is completing limited construction activities on Plant Franklin Unit 3 to preserve the long-term viability of the project but has deferred final completion until the 2008-2011 period. The length of the deferral period will depend on forecasted capacity needs and other wholesale market opportunities. Southern Power is continuing to explore alternatives for its existing capacity. On December 5, 2003, Mississippi Power filed a request with the Mississippi Public Service Commission (MPSC) to include 266 megawatts of Plant Daniel units 3 and 4 generating capacity in jurisdictional cost of service. See Note 3 to the financial statements under "Uncontracted Generating Capacity" and "Mississippi Power Regulatory Filing" for additional information.
On July 14, 2003, Mirant filed for voluntary reorganization under Chapter 11 with the U.S. Bankruptcy Court. 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 related to Mirant discussed in Note 3 to the financial statements under "Mirant Related Matters." Also, Southern Company has joint and several liability with Mirant regarding the joint consolidated federal income tax return as discussed in Note 5 to the financial statements. If Southern Company is ultimately required to make any payments related to these potential obligations, Mirant's indemnification obligation to Southern Company would represent an unsecured pre-bankruptcy claim, subject to compromise pursuant to Mirant's final reorganization plan.
Nuclear security legislation was recently introduced and considered in Congress both as a free-standing bill in the Senate and as a part of comprehensive energy legislation in a House-Senate Conference Report. Neither of the proposals has been enacted. The Nuclear Regulatory Commission (NRC) also ordered additional security measures for licensees in 2003. Southern Company is in the process of implementation and must be in full compliance with these orders by October 29, 2004. The requirements of the latest orders will have an impact on Southern Company's nuclear power plants and result in increased operation and maintenance expenses as well as additional capital expenditures. The precise impact of the new requirements will depend upon the details of the implementation of the new requirements, which have not been finalized.
Southern Company is involved in various matters being litigated, regulatory matters, and significant tax related issues that could affect future earnings. 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2003 Annual Report
accounting policies and estimates described below with the Audit Committee of Southern Company's Board of Directors.
Electric Utility Regulation
Southern Company's retail operating companies, which comprise approximately 85 percent of Southern Company's total earnings, are subject to retail regulation by their respective state public service commissions and wholesale regulation by the FERC. These regulatory agencies set the rates the retail operating companies are permitted to charge customers based on allowable costs. As a result, the retail operating companies apply FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of Statement No. 71 has a further effect on the company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the retail operating companies; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and post-retirement 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. However, adverse legislation and 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" and Note 3 to the financial statements for more information regarding certain of these contingencies. Southern Company and its subsidiaries periodically evaluate their exposure to such risks and record 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 or those of its subsidiaries. These events or conditions include the following:
o 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. o Changes in existing income tax regulations or changes in IRS interpretations of existing regulations. o 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. o Identification and evaluation of other potential lawsuits or complaints in which Southern Company or its subsidiaries may be named as a defendant. o Resolution or progression of existing matters through the legislative process, the court systems, the IRS, or the EPA.
Plant Daniel Capacity
As discussed in Note 3 to the financial statements, Mississippi Power requested and received an interim accounting order from the MPSC on December 16, 2003. The order directed Mississippi Power to expense and record in 2003 a regulatory liability of $60 million pending the conclusion of the MPSC's evaluation of Mississippi Power's request to include an additional 266 megawatts of Plant Daniel units 3 and 4 generating capacity in jurisdictional cost of service. The MPSC is not expected to complete its evaluation and issue a final order until the second quarter of 2004. Management believes that the interim accounting order represents a probable liability and that recognition of the expense in 2003 is appropriate. However, if the MPSC ultimately refuses Mississippi Power's request, the regulatory liability will be required to be reversed.
New Accounting Standards
Prior to January 2003, Southern Company accrued for the ultimate cost of retiring most long-lived assets over the life of the related asset through depreciation expense. FASB Statement No. 143, Accounting for Asset Retirement Obligations established new accounting and reporting standards for legal obligations associated with the ultimate cost of retiring long-lived assets. The
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2003 Annual Report
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. Additionally, non-regulated companies are no longer permitted to continue accruing future retirement costs for long-lived assets that they do not have a legal obligation to retire. For more information regarding the impact of adopting this standard effective January 1, 2003, see Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal."
FASB Statement No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, which further amends and clarifies the accounting and reporting for derivative instruments, became effective generally for financial instruments entered into or modified after June 30, 2003. Current interpretations of Statement No. 149 indicate that certain electricity forward transactions subject to unplanned netting -- including those typically referred to as "book outs" -- may only qualify as cash flow hedges if an entity can demonstrate that physical delivery or receipt of power occurred. Southern Company's forward electricity contracts continue to be exempt from fair value accounting requirements or to qualify as cash flow hedges, with the related gains and losses deferred in other comprehensive income. The implementation of Statement No. 149 did not have a material effect on Southern Company's financial statements.
In July 2003, the Emerging Issues Task Force (EITF) of FASB issued EITF No. 03-11, which became effective on October 1, 2003. The standard addresses the reporting of realized gains and losses on derivative instruments and is being interpreted to require book outs to be recorded on a net basis in operating revenues. Adoption of this standard did not have a material impact on Southern Company's financial statements.
FASB Interpretation No. 46, Consolidation of Variable Interest Entities, which was originally issued in January 2003, requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. Southern Company's previous interest in a variable interest entity related to Mississippi Power's lease arrangement for certain facilities at Plant Daniel was restructured prior to the original effective date of July 1, 2003, and is no longer subject to Interpretation No. 46. See Note 7 to the financial statements under "Operating Leases" for additional information. In December 2003, the FASB revised Interpretation No. 46 and deferred the effective date until March 31, 2004, for interests held in variable interest entities other than special purpose entities.
Current analysis indicates that the trusts established by Southern Company and the retail operating companies to issue preferred securities are variable interest entities under Interpretation No. 46, and that Southern Company and the retail operating companies are not the primary beneficiaries of these trusts. If this conclusion is finalized, effective March 31, 2004, the trust assets and liabilities -- including the preferred securities issued by the trusts -- will be deconsolidated. The investments in the trusts and the loans from the trusts to Southern Company and the retail operating companies will be reflected as equity method investments and as long-term notes payable to affiliates, respectively, on the Consolidated Balance Sheets. Based on December 31, 2003 values, this treatment would result in an increase of approximately $59 million to both total assets and total liabilities. See Note 6 to the financial statements under "Mandatorily Redeemable Preferred Securities" for additional information.
Southern Company has also identified certain other significant variable interest investments. These include two entities that produce synthetic fuel and are further described in Note 3 to the financial statements under "Synthetic Fuel Tax Credits." Southern Company is not the primary beneficiary of these entities. Southern Company also holds an 85 percent limited partnership investment in an energy/telecom venture capital fund that is currently accounted for under the equity method. At December 31, 2003, this investment totaled $17 million; the company has committed to a maximum investment of $75 million. Southern Company is continuing to review its transactions in light of the revised Interpretation No. 46; however, adoption is not currently expected to have a material impact on Southern Company's financial statements.
In May 2003, the FASB issued Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity, which requires classification of certain financial instruments within its scope, including shares that are mandatorily redeemable, as liabilities. Statement No. 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise on July 1, 2003. In accordance with Statement No. 150, mandatorily redeemable preferred securities are reflected in the Consolidated Balance Sheets as liabilities. The adoption of Statement No. 150 had no impact on the Consolidated Statements of Income and Cash Flows.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2003 Annual Report
FINANCIAL CONDITION AND LIQUIDITY - ---------------------------------
Overview
Southern Company's financial condition continues to be strong. At December 31, 2003, each of the retail operating companies was within its allowed range of return on equity. They operated at high levels of reliability while achieving industry-leading customer satisfaction levels and continuing to have retail prices below the national average. Also, earnings from the competitive generation business and other business activities made a significant contribution to the company's earnings goal of 5 percent average long-term growth.
At the close of 2003, the market value of Southern Company's common stock was $30.25 per share, compared with book value of $13.13 per share. The market-to-book value ratio was 230 percent at the end of 2003, compared with 233 percent at year-end 2002.
Gross property additions to utility plant were $2.0 billion in 2003. The majority of funds needed for gross property additions since 2000 has been provided from operating activities. The Consolidated Statements of Cash Flows provide additional details.
Sources of Capital
Southern Company intends to meet its future capital needs through internal cash flow and externally through the issuance of debt, preferred securities, and equity. The amount and timing of additional equity capital to be raised in 2004 - -- as well as in subsequent years -- will be contingent on Southern Company's investment opportunities. The company does not currently anticipate any equity offerings in 2004. Equity capital can be provided from any combination of the company's stock plans, private placements, or public offerings.
The retail operating companies 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. However, the type and timing of any financings -- if needed -- will depend on market conditions and regulatory approval. In recent years, financings primarily have utilized unsecured debt and preferred securities.
Southern Power will use both external funds and equity capital from Southern Company to finance its construction program. External funds are expected to be obtained from the issuance of unsecured senior debt and commercial paper or through existing credit arrangements from banks.
Southern Company and each operating company obtain financing separately without credit support from any affiliate. Currently, Southern Company provides limited credit support to Southern Power. 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. In accordance with the Public Utility Holding Company Act, most loans between affiliated companies must be approved in advance by the Securities and Exchange Commission (SEC).
Southern Company's current liabilities 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 various internal and external sources of liquidity. At the beginning of 2004, Southern Company and its subsidiaries had approximately $311 million of cash and cash equivalents and $3.5 billion of unused credit arrangements with banks, as shown in the following table. In addition, Southern Company has substantial cash flow from operating activities and access to the capital markets, including commercial paper programs, to meet liquidity needs. Cash flows from operating activities were $3.1 billion in 2003, $2.8 billion in 2002, and $2.4 billion in 2001.
At the beginning of 2004, bank credit arrangements are as follows:
Expires ------------------------------ Total Unused 2004 & Beyond - ---------------------------------------------------------------- (in millions) $3,496 $3,476 $2,806 $670 - ----------------------------------------------------------------
Approximately $2.25 billion of the credit facilities expiring in 2004 allow for the execution of term loans for an additional two-year period and $265 million allow for the execution for one-year term loans. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2003 Annual Report
Financing Activities
During 2003, Southern Company and its subsidiaries issued $3.5 billion of long-term debt and $125 million of preferred securities. In addition, Southern Company issued 18 million new shares of common stock through the company's stock plans and realized proceeds of $470 million. The issuances were used to refund $3.0 billion of long-term debt and $480 million of mandatorily redeemable preferred securities and to provide $575 million of permanent financing for Southern Power's new generating facilities. The remainder was used to reduce short-term debt, provide capital contributions to subsidiaries, and fund Southern Company's ongoing construction program.
Subsequent to December 31, 2003, the retail operating companies have issued $850 million of securities to redeem $400 million of long-term debt and mandatorily redeemable preferred securities and for other corporate purposes.
Off-Balance Sheet Financing Arrangements
In May 2001, Mississippi Power began the initial 10-year term of a lease agreement signed in 1999 for a combined cycle generating facility built at Plant Daniel. The facility cost 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 percent 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 under FASB Statement No. 13. The lease also provides for a residual value guarantee -- approximately 73 percent of the acquisition cost -- by Mississippi Power that is due upon termination of the lease in the event that the company 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 regarding this lease.
Credit Rating Risk
Southern Company and its subsidiaries do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are contracts that could require collateral - -- but not accelerated payment -- in the event of a credit rating change to below investment grade. These contracts are primarily for physical electricity purchases and sales, fixed-price physical gas purchases, and agreements covering interest rate swaps. At December 31, 2003, the maximum potential collateral requirements under the electricity purchase and sale contracts were approximately $415 million. Generally, collateral may be provided for by a Southern Company guaranty, a letter of credit, or cash. At December 31, 2003, there were no material collateral requirements for the gas purchase contracts or other financial instrument agreements.
Market Price Risk
Southern Company is exposed to market risks, including changes in interest rates and certain energy-related commodity prices. 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.
To mitigate exposure to interest rates, the company has entered into interest rate swaps that have been designated as hedges. The weighted average interest rate on $1.0 billion variable long-term debt that has not been hedged at December 31, 2003 was 1.5 percent. 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 $10 million at December 31, 2003. The company is not aware of any facts or circumstances that would significantly affect such exposures in the near term. For further information, see notes 1 and 6 to the financial statements under "Financial Instruments."
Due to cost-based rate regulations, the retail 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 shift substantially all fuel cost responsibility to the purchaser. To mitigate residual risks relative to movements in electricity prices, the retail operating companies and Southern Power enter into
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2003 Annual Report
fixed price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into similar contracts for gas purchases. The retail operating companies have implemented fuel-hedging programs at the instruction of their respective public service commissions. Southern Company GAS also has gas-hedging programs to substantially mitigate its exposure to price volatility for its gas purchases.
The fair value of changes in energy-related derivative contracts and year-end valuations were as follows at December 31:
Changes in Fair Value - ---------------------------------------------------------------- 2003 2002 - ---------------------------------------------------------------- (in millions) Contracts beginning of year $ 47.3 $ 1.3 Contracts realized or settled (73.2) (32.2) New contracts at inception - - Changes in valuation techniques - - Current period changes 41.7 78.2 - ---------------------------------------------------------------- Contracts end of year $ 15.8 $ 47.3 ================================================================
Source of 2003 Year-End Valuation Prices - --------------------------------------------------------------- Maturity Total --------------------- Fair Value 2004 2005-2006 - --------------------------------------------------------------- (in millions) Actively quoted $15.8 $16.9 $(1.1) External sources - - - Models and other methods - - - - --------------------------------------------------------------- Contracts end of year $15.8 $16.9 $(1.1) ===============================================================
Unrealized gains and losses from mark to market adjustments on derivative contracts related to the retail 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 retail operating companies' fuel cost recovery clauses. In addition, unrealized gains and losses on energy-related derivatives used by Southern Power and Southern Company GAS 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 income statement as incurred. At December 31, 2003, the fair value of derivative energy contracts was reflected in the financial statements as follows:
Amounts - ---------------------------------------------------------------- (in millions) Regulatory liabilities, net $14.9 Other comprehensive income 1.5 Net income (0.6) - ---------------------------------------------------------------- Total fair value $15.8 ================================================================
Unrealized pre-tax gains (losses) of $(2) million, $(5) million, and $9 million were recognized in income in 2003, 2002, and 2001, respectively. Southern Company is exposed to market price risk in the event of nonperformance by counterparties to the derivative energy 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."
Capital Requirements and Contractual Obligations
The construction program of Southern Company is currently estimated to be $2.2 billion for 2004, $2.2 billion for 2005, and $2.6 billion for 2006. Environmental expenditures included in these amounts are $349 million, $403 million, and $646 million for 2004, 2005, and 2006, respectively. Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Southern Company has approximately 1,200 megawatts of new generating capacity scheduled to be placed in service by 2005. The additional new capacity will be dedicated to the wholesale market and owned by Southern Power. In addition,
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2003 Annual Report
capital improvements, including those needed to meet the environmental standards previously discussed for the retail operating companies' generation, transmission, and distribution facilities are ongoing.
As a result of requirements by the NRC, Alabama Power and Georgia Power have established external trust funds for nuclear decommissioning costs. For additional information, see Note 1 to the financial statements under "Nuclear Decommissioning." Also, as discussed in Note 1 to the financial statements under "Revenues and Fuel Costs," in 1993 the DOE implemented a special assessment over a 15-year period on utilities with nuclear plants to be used for the decontamination and decommissioning of its nuclear fuel enrichment facilities.
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 retail 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 and distributions, preferred 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 2003 Annual Report
Cautionary Statement Regarding Forward-Looking Information
Southern Company's 2003 Annual Report includes forward-looking statements in addition to historical information. Forward-looking information includes, among other things, statements concerning the strategic goals for Southern Company's wholesale business, estimated construction and other expenditures, and Southern Company's projections for energy sales and its goals for future generating capacity, dividend payout ratio, earnings per share, and earnings growth. 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 comparable terminology. Southern Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include: o 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 and also changes in environmental, 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; o current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries and current IRS audits; o the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate; o the impact of fluctuations in commodity prices, interest rates, and customer demand; o available sources and costs of fuels; o ability to control costs; o investment performance of Southern Company's employee benefit plans; o advances in technology; o state and federal rate regulations and pending and future rate cases and negotiations; o effects of and changes in political, legal, and economic conditions and developments in the United States, including the current soft economy; o the performance of projects undertaken by the non-traditional business and the success of efforts to invest in and develop new opportunities; o internal restructuring or other restructuring options that may be pursued; o 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; o the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due; o the ability to obtain new short- and long-term contracts with neighboring utilities; o the direct or indirect effects on Southern Company's business resulting from the terrorist incidents on September 11, 2001, or any similar incidents or responses to such incidents; o financial market conditions and the results of financing efforts, including Southern Company's and its subsidiaries' credit ratings; o the ability of Southern Company and its subsidiaries to obtain additional generating capacity at competitive prices; o weather and other natural phenomena; o the direct or indirect effects on Southern Company's business resulting from the August 2003 power outage in the Northeast, or any similar incidents; o the effect of accounting pronouncements issued periodically by standard-setting bodies; and o other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed from time to time with the SEC.
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NOTES TO FINANCIAL STATEMENTS Southern Company and Subsidiary Companies 2002 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Southern Company is the parent company of five retail operating companies, Southern Power Company (Southern Power), Southern Company Services (SCS), Southern Communications Services (Southern LINC), Southern Company Gas (Southern Company GAS), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The retail operating companies -- Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric -- provide electric service in four Southeastern states. Southern Power constructs, owns, and manages Southern Company's competitive generation assets and sells electricity at market-based rates in the wholesale market. Contracts among the retail operating companies and Southern Power -- related to jointly owned generating facilities, interconnecting transmission lines, or the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission (SEC). SCS -- the system service company - -- provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern Company GAS is a competitive retail natural gas marketer serving customers in Georgia. Southern Holdings is an intermediate holding subsidiary for Southern Company's investments in synthetic fuels and leveraged leases and an energy services business. Southern Nuclear operates and provides services to Southern Company's nuclear power plants.
On April 2, 2001, the spin off of Mirant Corporation (Mirant) was completed. As a result of the spin off, Southern Company's financial statements and related information reflect Mirant as discontinued operations. For additional information regarding Mirant, see Note 3 under "Mirant Related Matters."
The financial statements reflect Southern Company's investments in the subsidiaries on a consolidated basis. The equity method is used for subsidiaries in which the company has significant influence but does not control. All material intercompany items have been eliminated in consolidation. Certain prior years' data presented in the consolidated financial statements have been reclassified to conform with the current year presentation.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both the company and its subsidiaries are subject to the regulatory provisions of the PUHCA. In addition, the retail operating companies and Southern Power are subject to regulation by the FERC, and the retail operating companies are also subject to regulation by their respective state public service commissions. 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.
Related Party Transactions
Alabama Power and Georgia Power purchase synthetic fuel from Alabama Fuel Products, LLC (AFP), an entity in which Southern Holdings holds a 30 percent ownership interest. Total fuel purchases for 2003 and 2002 were $301 million and $211 million, respectively. The financial statements reflect the elimination of 30 percent of these amounts. Another subsidiary of Southern Holdings provides services to AFP. In connection with these services, revenues of approximately $74 million and $44 million in 2003 and 2002, respectively, have been billed to an entity that is a subsidiary of AFP's majority owner.
Revenues and Fuel Costs
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 are accrued at the end of each fiscal period. Fuel costs are expensed as the fuel is used. Electric rates for the retail 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 recoverable fuel costs and amounts actually recovered in current regulated rates.
Southern Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts continued to average less than 1 percent of revenues.
Fuel expense includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear
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fuel. Total charges for nuclear fuel included in fuel expense amounted to $138 million in 2003, $134 million in 2002, and $133 million in 2001. Alabama Power and Georgia Power have contracts with 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 January 1998 as required by the contracts, and the companies are pursuing legal remedies against the government for breach of contract. Sufficient pool storage capacity for spent fuel is available at Plant Farley to maintain full-core discharge capability until the refueling outages scheduled for 2006 and 2008 for units 1 and 2, respectively. Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into 2015. At Plant Hatch, an on-site dry storage facility became operational in 2000 and can be expanded to accommodate spent fuel through the life of the plant. Construction of an on-site dry storage facility at Plant Farley is in progress and scheduled for operation in 2005. Construction of an on-site dry storage facility at Plant Vogtle will begin in sufficient time to maintain pool full-core discharge capability.
Also, the Energy Policy Act of 1992 required the establishment of a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants. This assessment is being paid over a 15-year period, which began in 1993. 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. Alabama Power and Georgia Power -- based on its ownership interest -- estimate their respective remaining liability at December 31, 2003, under this law to be approximately $13 million and $10 million.
Income 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 lives of the related property.
Regulatory Assets and Liabilities
The retail 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. 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 Consolidated Balance Sheets at December 31 relate to:
2003 2002 Note - ---------------------------------------------------------------- (in millions) Deferred income tax charges $ 874 $ 898 (a) Loss on reacquired debt 326 313 (b) DOE assessments 26 33 (c) Vacation pay 97 98 (d) Building lease 54 54 (f) Generating plant outage costs 35 38 (f) Other assets 75 73 (f) Asset retirement obligations (138) - (a) Other cost of removal obligations (1,269) (1,944) (a) Deferred income tax credits (409) (450) (a) Accelerated cost recovery (115) (229) (e) Plant Daniel capacity (60) - (g) Storm damage reserves (53) (38) (f) Fuel-hedging liabilities (13) (38) (c) Environmental remediation reserves (41) (42) (f) Deferred purchased power (92) (63) (f) Other liabilities (13) (12) (f) - ---------------------------------------------------------- Total $ (716) $(1,309) ========================================================== 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 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) Assessments for the decontamination and decommissioning of the DOE's nuclear fuel enrichment facilities are recorded annually from 1993 through 2008. 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. (d) Recorded as earned by employees and recovered as paid, generally within one year. (e) Amortized over three-year period ending in 2004. (f) Recorded and recovered or amortized as approved by the appropriate state public service commissions. (g) See Note 3 under "Mississippi Power Regulatory Filing."
In the event that a portion of an operating company's operations is no longer subject to the provisions of FASB Statement No. 71, the company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the operating company would be required to determine if any impairment to other assets exists,
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including plant, and write down the assets, if impaired, to their fair value. All regulatory assets and liabilities are to be reflected in rates.
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.1 percent in 2003, 3.2 percent in 2002, and 3.4 percent in 2001. 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 previous rate orders, Georgia Power recorded accelerated depreciation and amortization amounting to $91 million in 2001. Effective January 2002, Georgia Power discontinued recording accelerated depreciation and amortization in accordance with a new retail rate order. Also, Georgia Power was ordered to amortize $333 million -- the cumulative balance previously expensed -- equally over three years as a credit to depreciation and amortization expense beginning January 2002. Also, effective January 2002, Georgia Power was ordered by the Georgia Public Service Commission (GPSC) to recognize new certified purchased power costs in rates evenly over the three years covered by the current retail rate order. As a result of this regulatory adjustment, Georgia Power recorded in depreciation and amortization expense $14 million and $63 million in 2003 and 2002, respectively. Georgia Power will record a credit to amortization expense of $77 million in 2004. See Note 3 under "Georgia Power Retail Rate Orders" for additional information.
Asset Retirement Obligations And Other Costs of Removal
In accordance with regulatory requirements, prior to January 2003, Southern Company followed the industry practice of accruing for the ultimate cost of retiring most long-lived assets over the life of the related asset as part of the annual depreciation expense provision. In accordance with SEC requirements, such amounts are reflected on the Consolidated Balance Sheet as regulatory liabilities. Effective January 1, 2003, Southern Company adopted FASB Statement No. 143, Accounting for Asset Retirement Obligations. Statement No. 143 establishes new accounting and reporting standards for legal obligations associated with the ultimate costs of retiring long-lived assets. The present value of the ultimate costs for an asset's future retirement must be recorded in the period in which the liability is incurred. The costs must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Additionally, Statement No. 143 does not permit the continued accrual of future retirement costs for long-lived assets that the company does not have a legal obligation to retire. However, the retail operating companies have received guidance regarding accounting for the financial statement impacts of Statement No.143 from their respective state public service commissions and will continue to recognize the accumulated removalcosts for other obligations as a regulatory liability. Therefore, the retail operating companies had no cumulative effect to net income resulting from the adoption of Statement No. 143.
The liability recognized to retire long-lived assets primarily relates to Southern Company's nuclear facilities, which include Alabama Power's Plant Farley and Georgia Power'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, 2003 was $808 million. In addition, the retail operating companies have retirement obligations related to various landfill sites, ash ponds, and underground storage tanks. The retail operating companies have also identified retirement obligations related to certain transmission and distribution facilities. However, liabilities for the removal of these transmission and distribution assets have not been recorded because no reasonable estimate can be made regarding the timing of the obligations. The retail operating companies will continue to recognize in the income statement allowed removal costs in accordance with each company's respective regulatory treatment. Any difference between costs recognized under Statement No. 143 and those reflected in rates are recognized as either a regulatory asset or liability and are reflected in the Consolidated Balance Sheets. See "Nuclear Decommissioning" for further information on amounts included in rates.
Details of the asset retirement obligations included in the Consolidated Balance Sheets are as follows:
- ---------------------------------------------------------------- (in millions) Balance beginning of year $ - Liabilities incurred 780 Liabilities settled - Accretion 55 Cash flow revisions 10 - ---------------------------------------------------------------- Balance end of year $845 ================================================================
If Statement No. 143 had been adopted on January 1, 2002, the pro-forma asset retirement obligations would have been $729 million.
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Nuclear Decommissioning
The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial nuclear power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. Alabama Power and Georgia Power have external trust funds to comply with the NRC's regulations. The funds set aside for decommissioning are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and state public utility commissions, as well as the Internal Revenue Service (IRS). Funds are invested in a tax efficient manner in a diversified mix of equity and fixed income securities. Equity securities typically range from 50 to 75 percent of the funds and fixed income securities from 25 to 50 percent. Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the respective state public service commissions. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission 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 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 based on the most current study as of December 31, 2003, for Alabama Power's Plant Farley and Georgia Power's ownership interests in plants Hatch and Vogtle were as follows:
Plant Plant Plant Farley Hatch Vogtle - ---------------------------------------------------------------- Site study year 2003 2003 2003 Decommissioning periods: Beginning year 2017 2034 2027 Completion year 2046 2065 2048 - ---------------------------------------------------------------- (in millions) Site study costs: Radiated structures $892 $497 $452 Non-radiated structures 63 49 58 - ---------------------------------------------------------------- Total $955 $546 $510 ================================================================
Significant assumptions: Inflation rate 4.5% 3.1% 3.1% Trust earning rate 7.0 6.6 6.6 - ----------------------------------------------------------------
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.
Annual provisions for nuclear decommissioning are based on an annuity method as approved by the respective state public service commissions. The amount expensed in 2003 and fund balances were as follows:
Plant Plant Plant Farley Hatch Vogtle - --------------------------------------------------------------- (in millions) Amount expensed in 2003 $18 $7 $2 Accumulated provisions: External trust funds, at fair value $385 $269 $154 Internal reserves 31 7 4 - --------------------------------------------------------------- Total $416 $276 $158 ===============================================================
Alabama Power's decommissioning costs for ratemaking are based on the site study. Effective January 1, 2002, the GPSC decreased Georgia Power's annual decommissioning costs for ratemaking to $9 million. This amount is based on the NRC generic estimate to decommission the radioactive portion of the facilities as of 2000. The estimates are $383 million and $282 million for plants Hatch and Vogtle, respectively. Assumptions used to determine these costs for ratemaking were an inflation rate of 4.5 percent and 4.7 percent for Alabama Power and Georgia Power, respectively, and a trust earning rate of 7.0 percent and 6.5 percent for Alabama Power and Georgia Power, respectively. Alabama Power and Georgia Power expect their respective state public service commissions to periodically review and adjust, if necessary, the amounts collected in rates for the anticipated cost of decommissioning.
In January 2002, Georgia Power received NRC approval for a 20-year extension of the license at Plant Hatch, which permits the operation of units 1 and 2 until 2034 and 2038, respectively. The site study decommissioning costs reflect the license extension; however, the updated costs will not be reflected in rates until the GPSC issues a new rate order, which is not expected until December 2004. Alabama Power filed an application with the NRC in September 2003 to extend the operating license for Plant Farley for an additional 20 years.
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Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized
In accordance with regulatory treatment, the retail operating companies record AFUDC. AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. Interest related to the construction of new facilities not included in the retail operating companies' regulated rates is capitalized in accordance with standard interest capitalization requirements.
Cash payments for interest totaled $603 million, $544 million, and $624 million in 2003, 2002, and 2001, respectively, net of amounts capitalized of $49 million, $59 million, and $57 million, respectively.
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 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 public service commission orders. Alabama Power accrues estimated refueling costs in advance of the unit's next refueling outage. Georgia Power defers and amortizes 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 retail accounting orders, both Georgia Power and Savannah Electric will defer the costs of certain significant inspection costs for the combustion turbines at Plant McIntosh and amortize such costs over 10 years, which approximates the expected maintenance cycle.
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 provision is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Leveraged Leases
Southern Company has several leveraged lease agreements -- ranging up to 45 years -- that relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for rent or depreciation and amortization, as well as interest on long-term debt related to these investments.
Southern Company's net investment in leveraged leases consists of the following at December 31:
2003 2002 - ---------------------------------------------------------------- (in millions) Net rentals receivable $1,512 $1,531 Unearned income (674) (740) - ---------------------------------------------------------------- Investment in leveraged leases 838 791 Deferred taxes arising from leveraged leases (351) (260) - ---------------------------------------------------------------- Net investment in leveraged leases $ 487 $ 531 ================================================================
A summary of the components of income from leveraged leases is as follows:
2003 2002 2001 - --------------------------------------------------------------- (in millions) Pretax leveraged lease income $66 $58 $59 Income tax expense 23 21 21 - --------------------------------------------------------------- Net leveraged lease income $43 $37 $38 ===============================================================
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Cash and Cash Equivalents
For purposes of the consolidated 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.
Stock Options
Southern Company accounts for its stock-based compensation plans in accordance with Accounting Principles Board Opinion No. 25. Accordingly, no compensation expense has been recognized because the exercise price of all options granted equaled the fair-market value on the date of grant.
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 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. This results in the deferral of related gains and losses in other comprehensive income or regulatory assets or liabilities as appropriate 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 Consolidated 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 does not equal fair value at December 31 were as follows:
Carrying Fair Amount Value - --------------------------------------------------------------- (in millions) Long-term debt: At December 31, 2003 $10,759 $10,971 At December 31, 2002 10,226 10,510 Preferred securities: At December 31, 2003 1,940 2,059 At December 31, 2002 2,428 2,498 - ---------------------------------------------------------------
The fair values were based on either closing market price or closing price of comparable instruments.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income and changes in the fair value of qualifying cash flow hedges and changes in additional minimum pension liability, less income taxes and reclassifications for amounts included in net income. Comprehensive income from discontinued operations also includes foreign currency translation adjustments, net of income taxes.
2. RETIREMENT BENEFITS
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with Employee Retirement Income Security Act (ERISA) requirements. No contributions to the plan are expected for the year ending December 31, 2004. Southern Company also provides certain non-qualified benefit plans for a selected group of management and highly compensated employees. Benefits under these non-qualified plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees. The retail operating companies fund related trusts to the extent required by their respective regulatory commissions. For the year ended December 31, 2004, postretirement benefit contributions are expected to total approximately $15 million.
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The measurement date for plan assets and obligations is September 30 for each year. In 2002, Southern Company adopted several plan changes that had the effect of increasing benefits to both current and future retirees.
Pension Plans
The accumulated benefit obligation for the pension plans was $4.2 billion in 2003 and $3.6 billion in 2002. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:
Projected Benefit Obligations -------------------- 2003 2002 - --------------------------------------------------------------- (in millions) Balance at beginning of year $4,094 $3,760 Service cost 115 109 Interest cost 261 277 Benefits paid (197) (184) Plan amendments 11 88 Actuarial (gain) loss 289 44 - --------------------------------------------------------------- Balance at end of year $4,573 $4,094 ===============================================================
Plan Assets ------------------ 2003 2002 - --------------------------------------------------------------- (in millions) Balance at beginning of year $4,600 $5,109 Actual return on plan assets 735 (343) Benefits paid (176) (166) - --------------------------------------------------------------- Balance at end of year $5,159 $4,600 ===============================================================
Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the IRS revenue code. The company's investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.
Plan Assets ------------------------------- Target 2003 2002 - ---------------------------------------------------------------- Domestic equity 37% 37% 35% International equity 20 20 18 Global fixed income 26 24 25 Real estate 10 11 12 Private equity 7 8 10 - ---------------------------------------------------------------- Total 100% 100% 100% ================================================================
The accrued pension costs recognized in the Consolidated Balance Sheets were as follows:
2003 2002 - --------------------------------------------------------------- (in millions) Funded status $586 $ 506 Unrecognized transition amount (26) (39) Unrecognized prior service cost 314 334 Unrecognized net (gain) loss (70) (115) - --------------------------------------------------------------- Prepaid pension asset, net 804 686 Portion included in benefit obligations 107 100 - --------------------------------------------------------------- Total prepaid assets recognized in the Consolidated Balance Sheets $911 $ 786 ===============================================================
In 2003 and 2002, amounts recognized in the Consolidated Balance Sheets for accumulated other comprehensive income and intangible assets to record the minimum pension liability related to the non-qualified plans were $77 million and $49 million and $42 million and $35 million, respectively.
Components of the pension plans' net periodic cost were as follows:
2003 2002 2001 - ------------------------------------------------------------- (in millions) Service cost $ 115 $ 109 $ 104 Interest cost 261 277 260 Expected return on plan assets (450) (449) (423) Recognized net gain (42) (65) (73) Net amortization 17 11 8 - -------------------------------------------------------------- Net pension cost (income) $ (99) $(117) $(124) ==============================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:
Accumulated Benefit Obligations --------------------- 2003 2002 - --------------------------------------------------------------- (in millions) Balance at beginning of year $1,461 $1,239 Service cost 25 21 Interest cost 93 91 Benefits paid (66) (62) Actuarial (gain) loss 142 172 - --------------------------------------------------------------- Balance at end of year $1,655 $1,461 ===============================================================
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Plan Assets --------------- 2003 2002 - --------------------------------------------------------------- (in millions) Balance at beginning of year $417 $425 Actual return on plan assets 70 (34) Employer contributions 101 88 Benefits paid (66) (62) - --------------------------------------------------------------- Balance at end of year $522 $417 ===============================================================
Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the IRS revenue code. The company's investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.
Plan Assets -------------------------------- Target 2003 2002 - ---------------------------------------------------------------- Domestic equity 43% 44% 38% International equity 17 18 16 Global fixed income 33 31 37 Real estate 4 4 5 Private equity 3 3 4 - ---------------------------------------------------------------- Total 100% 100% 100% ================================================================
The accrued postretirement costs recognized in the Consolidated Balance Sheets were as follows:
2003 2002 - ---------------------------------------------------------------- (in millions) Funded status $(1,133) $(1,043) Unrecognized transition obligation 144 159 Unrecognized prior service cost 211 225 Unrecognized net loss (gain) 357 239 Fourth quarter contributions 19 51 - ---------------------------------------------------------------- Accrued liability recognized in the Consolidated Balance Sheets $ (402) $ (369) ================================================================
Components of the postretirement plans' net periodic cost were as follows:
2003 2002 2001 - -------------------------------------------------------------- (in millions) Service cost $ 25 $ 21 $ 22 Interest cost 93 91 88 Expected return on plan assets (47) (42) (40) Net amortization 30 29 26 - -------------------------------------------------------------- Net postretirement cost $101 $ 99 $ 96 ==============================================================
The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations and the net periodic costs for the pension and postretirement benefit plans were as follows:
2003 2002 2001 - --------------------------------------------------------------- Discount 6.00% 6.50% 7.50% Annual salary increase 3.75 4.00 5.00 Long-term return on plan assets 8.50 8.50 8.50 - ---------------------------------------------------------------
The company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.
An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 8.25 percent for 2003, decreasing gradually to 5.25 percent through the year 2010 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2003, as follows:
1 Percent 1 Percent Increase Decrease - ---------------------------------------------------------------- (in millions) Benefit obligation $140 $124 Service and interest costs 10 8 - ----------------------------------------------------------------
Employee Savings Plan
Southern Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The company provides a 75 percent matching contribution up to 6 percent of an employee's base salary. Total matching contributions made to the plan for the years 2003, 2002, and 2001 were $55 million, $53 million, and $51 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, and citizen enforcement of environmental requirements, has increased generally throughout the United
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States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, 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 Related Matters
Mirant Spin Off
In April 2000, Southern Company announced an initial public offering of up to 19.9 percent of Mirant and its intention to spin off the remaining ownership of Mirant to Southern Company stockholders. On October 2, 2000, Mirant completed its initial public offering of 66.7 million shares. On April 2, 2001, the tax-free distribution of Mirant shares was completed at a ratio of approximately 0.4 for every share of Southern Company common stock held at record date.
Potential Mirant Restatement
In November 2002, Mirant first announced that it had identified accounting errors in previously issued financial statements. Mirant has restated and reduced its net income for 2001 by $159 million. Mirant has stated that the specific quarters in 2001 to which the overstatement apply have not been determined. If any adjustments are necessary prior to April 2, 2001, before Southern Company's spin off of Mirant, then Southern Company's earnings from discontinued operations for such periods would be affected. The impact of any such adjustments cannot be determined until Mirant's 2001 revised quarterly financial statements are filed and would not affect Southern Company's 2002 or any future financial statements.
Mirant Bankruptcy
On July 14, 2003, Mirant filed for voluntary reorganization under Chapter 11 with the U.S. Bankruptcy Court. 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 later in this note. Also, Southern Company has joint and several liability with Mirant regarding the joint consolidated federal income tax return as discussed in Note 5. Under the terms of the separation agreement, Mirant agreed to indemnify Southern Company for costs associated with these guarantees, lawsuits, and additional IRS assessments. The impact of Mirant's bankruptcy filing on Mirant's indemnity obligations, if any, cannot now be determined. If Southern Company is ultimately required to make any payments related to these potentially material obligations, Mirant's indemnification obligation to Southern Company would represent an unsecured pre-bankruptcy claim, subject to compromise pursuant to Mirant's final reorganization plan.
The Bankruptcy Code automatically stays all litigation as to Mirant. A motion filed with the bankruptcy court requesting an extension of this automatic stay to all other non-debtor defendants, including Southern Company and the named current and/or former Southern Company officers, was granted in November 2003. Although the Mirant securities litigation is stayed until further order from the bankruptcy court, Mirant is authorized to agree with parties in pending actions to allow discovery or other matters to proceed without violating the stay. Mirant and plaintiffs' counsel in the Mirant securities litigation have agreed that document discovery may proceed. On October 23, 2003, the bankruptcy court entered an order authorizing Southern Company's insurance companies to pay related defense costs.
On February 20, 2004, the Official Committee of Unsecured Creditors of Mirant informed Southern Company of its intent to examine Southern Company in accordance with federal bankruptcy rules to determine whether there is a legitimate basis to bring claims against Southern Company in connection with Mirant's initial public offering, Southern Company's spinoff of Mirant, and the related separation agreements.
The final outcome of these matters cannot now be determined.
California Electricity Markets Investigation
Southern Company received a subpoena in November 2002 to provide information to a federal grand jury in the Northern District of California. The subpoena covered a number of broad areas, including specific information regarding electricity production and sales activities in California. Mirant participated in energy marketing and trading in California during the period relevant to the subpoena. Southern Company has produced documents in response to the subpoena and has fully cooperated in the investigation.
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
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were added as defendants in a putative class action lawsuit that several Mirant shareholders originally filed against Mirant and certain Mirant officers in May 2002. The original lawsuit was based on allegations related to alleged improper energy trading and marketing activities involving the California energy market. 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.
On July 14, 2003, the court dismissed all claims based on Mirant's alleged improper energy trading and marketing activities involving the California energy market. The remaining claims are based on alleged false statements and omissions in Mirant's prospectus for its initial public offering and accounting-related issues previously disclosed by Mirant. Such claims do not allege any improper trading and marketing activity, accounting errors, or material misstatements or omissions on the part of Southern Company, but rather 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 on September 3, 2003. Plaintiffs have also filed a motion for class certification.
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 are also named as defendants in this lawsuit. Except for limited document discovery, litigation has been stayed until further order from the bankruptcy court. The final outcome of these matters cannot now be determined.
Mirant ERISA Litigation
In April 2003, a retired employee of Mirant filed a complaint in the U.S. District Court for the Northern District of Georgia alleging violations of ERISA and naming as defendants Mirant, Southern Company, several current and former directors and officers of Mirant and/or Southern Company, and "Unknown Fiduciary Defendants 1-100." In June 2003, a substantially similar complaint was filed. Neither complaint contained any specific allegations of wrongdoing with respect to Southern Company. On September 2, 2003, the court consolidated all pending and future ERISA actions arising out of the same facts, and the plaintiffs filed a consolidated amended ERISA complaint on September 23, 2003. The plaintiffs sought to represent a class of persons who were participants in or beneficiaries of certain Mirant employee benefit plans between September 27, 2000, and July 22, 2003. The consolidated amended complaint named as defendants Mirant, certain Mirant benefit committees, Southern Company, and several of Mirant's current and former officers, directors, and employees. The consolidated amended complaint alleged that the defendants breached their fiduciary duties and violated ERISA by failing to investigate whether Mirant stock was a prudent investment for the plans, by continuing and promoting Mirant stock as an investment alternative for participants in the plans, and by failing to disclose information about Mirant's financial condition and about its improper activities in the California energy markets.
On February 19, 2004, plaintiffs dismissed Southern Company from this action without prejudice. The plaintiffs are not barred from naming Southern Company in some future lawsuit, but management believes the possibility of having to pay damages in any such lawsuit is remote.
Mobile Energy Services' Petition for Bankruptcy
Mobile Energy Services Holdings (MESH) is the owner and operator of a facility that generates electricity, produces steam, and processes black liquor as part of a pulp and paper complex in Mobile, Alabama. In January 1999, MESH filed a petition for Chapter 11 bankruptcy with the U.S. Bankruptcy Court. In 2001, MESH filed an amended plan of reorganization, which the U.S. Bankruptcy Court confirmed in September 2003. The plan became effective in late 2003 and Southern Company's equity interest in MESH - which had been written off entirely prior to 2001 - was extinguished. Southern Company will continue to have contingent liabilities to the pulp and paper complex owners associated with a guarantee of certain potential environmental obligations and with a potential obligation to fund a maintenance reserve account that expires in 2019 and 2021, respectively. The combined maximum contingent liabilities were $19 million at December 31,
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2003. MESH and Mirant have each separately agreed to indemnify Southern Company for any amounts required to be paid under such obligations. The final outcome of these matters cannot now be determined.
Georgia Power Potentially Responsible Party Status
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. Georgia Power has recognized $34 million in cumulative expenses through December 31, 2003, for the assessment and anticipated cleanup of sites on the Georgia Hazardous Sites Inventory. In addition, in 1995 the Environmental Protection Agency (EPA) designated Georgia Power and four other unrelated entities as potentially responsible parties at a site in Brunswick, Georgia, that is listed on the federal National Priorities List. Georgia Power has contributed to the removal and remedial investigation and feasibility study costs for the site. Additional claims for recovery of natural resource damages at the site are anticipated. As of December 31, 2003, Georgia Power had recorded approximately $6 million in cumulative expenses associated with Georgia Power's agreed-upon share of the removal and remedial investigation and feasibility study costs for the Brunswick site.
The final outcome of each of these matters cannot now be determined. However, based on the currently known conditions at these sites and the nature and extent of Georgia Power's activities relating to these sites, management does not believe that the company's additional liability, if any, at these sites would be material to the financial statements.
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 Alabama Power, Georgia Power, and SCS. The complaint alleged violations of the New Source Review (NSR) provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia and violations of related state laws. The civil action requested penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued to the retail operating companies notices of violation relating to 10 generating facilities, which include the five facilities mentioned previously. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notices of violation and to add Gulf Power, Mississippi Power, and Savannah Electric as defendants.
In August 2000, the U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and granted SCS' motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. In March 2001, the court granted the EPA's motion to add Savannah Electric as a defendant, but it denied the motion to add Gulf Power and Mississippi Power based on lack of jurisdiction in Georgia over those companies. As directed by the court, the EPA refiled its amended complaint limiting claims to those brought against Georgia Power and Savannah Electric. In addition, the EPA refiled its claims against Alabama Power in the U.S. District Court for the Northern District of Alabama. These complaints allege violations with respect to eight coal-fired generating facilities in Alabama and Georgia, and they request the same kinds of relief as was requested in the original complaint, i.e. penalties and injunctive relief, including installation of the best available control technology. The EPA has not refiled against Gulf Power, Mississippi Power, or SCS.
The actions against Alabama Power, Georgia Power, and Savannah Electric were stayed in the spring of 2001 during the appeal of a very similar NSR enforcement action against the Tennessee Valley Authority (TVA) before the U.S. Court of Appeals for the Eleventh Circuit. The TVA appeal involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and Savannah Electric. Because the final resolution of the TVA appeal could have a significant impact on Alabama Power and Georgia Power, both companies have been involved in that appeal. On June 24, 2003, the court of appeals issued its ruling in the TVA case. It found unconstitutional the statutory scheme set forth in the Clean Air Act that allowed the EPA to impose penalties for failing to comply with an administrative compliance order, like the one issued to TVA, without the EPA having to prove the underlying violation. Thus, the court of appeals held that the compliance order was of no legal consequence, and TVA was free to ignore it. The court did not, however, rule directly on the substantive legal issues about the proper interpretation and application of certain NSR provisions that had been raised in the TVA appeal. On September 16, 2003, the court of appeals denied the EPA's request for a rehearing of the decision. On February 13, 2004, the EPA petitioned the U.S. Supreme Court to review the decision of the court of appeals. The EPA also filed a motion to lift the stay in the action against Alabama Power. At this time, no party to the Georgia Power and Savannah Electric action, which was administratively closed two years ago, has asked the court to reopen that case.
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Since the inception of the NSR proceedings against Georgia Power, Alabama Power, and Savannah Electric, the EPA has also been proceeding with similar NSR enforcement actions against other utilities, involving many of the same legal issues. In each case, the EPA alleged that the utilities failed to comply with the NSR permitting requirements when performing maintenance and construction activities at coal-burning plants, which activities the utilities considered to be routine or otherwise not subject to NSR. In 2003, district courts addressing these cases issued opinions that reached conflicting conclusions.
In October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act clarifying the scope of the existing Routine Maintenance, Repair, and Replacement exclusion. On December 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit stayed the effectiveness of these revisions pending resolution of related litigation. In January 2004, the Bush Administration announced that it would continue to enforce the existing rules.
Southern Company believes that its retail operating companies complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome in any one of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
Plant Wansley Environmental Litigation
On December 30, 2002, the Sierra Club, Physicians for Social Responsibility, Georgia ForestWatch, and one individual filed a civil suit in the U.S. District Court in Georgia against Georgia Power for alleged violations of the Clean Air Act at four of the generating units at Plant Wansley. The complaint alleges Clean Air Act violations at both the existing coal-fired units and the new combined cycle units. Specifically, the plaintiffs allege (1) opacity violations at the coal-fired units, (2) violations of a permit provision that requires the combined cycle units to operate above certain levels, (3) violation of nitrogen oxide emission offset requirements, and (4) violation of hazardous air pollutant requirements. The civil action requests injunctive and declaratory relief, civil penalties, a supplemental environmental project, and attorneys' fees. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit.
On June 19, 2003, the court granted Georgia Power's motion to dismiss the allegations regarding hazardous air pollutants and denied Georgia Power's motion to dismiss the allegations regarding emission offsets. On August 29, 2003, Georgia Power filed a motion for partial summary judgment regarding emission offsets. On January 20, 2004, Georgia Power filed a motion for summary judgment on the remaining three counts, and the plaintiffs have filed motions for partial summary judgment. The case is currently scheduled for trial during the summer of 2004. While Georgia Power believes that it has complied with applicable laws and regulations, an adverse outcome could require payment of substantial penalties. The final outcome of this matter cannot now be determined.
Race Discrimination Litigation
In July 2000, a lawsuit alleging race discrimination was filed by three Georgia Power employees against Georgia Power, Southern Company, and SCS in the Superior Court of Fulton County, Georgia. Shortly thereafter, the lawsuit was removed to the U.S. District Court for the Northern District of Georgia. The lawsuit also raised claims on behalf of a purported class. The plaintiffs seek compensatory and punitive damages in an unspecified amount, as well as injunctive relief. In August 2000, the lawsuit was amended to add four more plaintiffs. Also, an additional indirect subsidiary of Southern Company, Southern Company Energy Solutions, was named a defendant.
In October 2001, the district court denied the plaintiffs' motion for class certification. The plaintiffs filed a motion to reconsider the order denying class certification, and the court denied the plaintiffs' motion to reconsider. In December 2001, the plaintiffs filed a petition in the U.S. Court of Appeals for the Eleventh Circuit seeking permission to file an appeal of the October 2001 decision, and this petition was denied. After discovery was completed on the claims raised by the seven named plaintiffs, the defendants filed motions for summary judgment on all of the named plaintiffs' claims. On March 31, 2003, the U.S. District Court for the Northern District of Georgia granted summary judgment in favor of the defendants on all claims raised by all seven plaintiffs. On April 23, 2003, plaintiffs filed an appeal to the U.S. Court of Appeals for the Eleventh Circuit challenging these adverse summary judgment rulings, as well as the District Court's October 2001 ruling denying class
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certification. Oral argument occurred on January 27, 2004, and the parties await the court's decision. The final outcome of this matter cannot now be determined.
Right of Way Litigation
Southern Company and certain of its subsidiaries, including Georgia Power, Gulf Power, Mississippi Power, and Southern Telecom (collectively, defendants), have been named as defendants in numerous lawsuits brought by landowners since 2001 regarding the installation and use of fiber optic cable over defendants' rights of way located on the landowners' property. 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 by defendants exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment. The plaintiffs seek compensatory and punitive damages and injunctive relief. With respect to 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, on November 7, 2003, the Second Circuit Court in Gadsden County, Florida, ruled in favor of the plaintiffs on their motion for partial summary judgment concerning liability. The question of damages, if any, will be decided at a future trial. In the event of an adverse verdict on damages, Gulf Power could appeal the verdicts on both liability and damages. Management of Southern Company and its subsidiaries believe that the defendant companies in the pending right of way litigation have complied with applicable laws and that the plaintiffs' claims are without merit. An adverse outcome in these matters could result in substantial judgments; however, the final outcome of these matters cannot now be determined.
In addition, in late 2001, certain subsidiaries of Southern Company, including Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, and Southern Telecom (collectively, defendants), 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 the telecommunications company in pending and future right of way litigation. The defendants believe that the plaintiff's claims are without merit. 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.
Income Tax Issues
Synthetic Fuel Tax Credits
Southern Company has investments in two entities that produce synthetic fuel and receive tax credits under Section 29 of the IRS revenue code. In April 2001, Southern Company acquired a 30 percent membership interest in AFP. In 1998, Southern Company acquired a 24.975 percent limited partnership interest in Carbontronics Synfuels Investors, L.P. (Carbontronics). At December 31, 2003, Southern Company's total investment in these entities was approximately $30 million.
On June 30, 2003, the IRS issued an announcement that suspended the issuance of new private letter rulings and indicated that it might also revoke existing private letter rulings for synthetic fuels Section 29 tax credits pending a review of the scientific validity of test procedures and results that have been presented as evidence that a significant chemical change occurred in such synthetic fuel. On October 29, 2003, the IRS announced that it has completed its review and determined that the test procedures and results used by taxpayers are scientifically valid if the procedures are applied in a consistent and unbiased manner. The IRS stated that the processes they approved do not produce the level of chemical change required by Section 29, but they will, nevertheless, resume issuing private letter rulings. The IRS will require taxpayers applying for future rulings to implement and maintain certain sampling and quality control procedures, as well as additional documentation and record retention procedures. The IRS also plans to extend these procedures to taxpayers already holding rulings on the issue of significant chemical change.
On October 30, 2003, the Senate Governmental Affairs Permanent Subcommittee on Investigations announced that it has begun a separate investigation of the synthetic fuel industry and its producers for potential abuses of these tax credits.
In January 2004, the IRS completed an audit of AFP for tax years 1999 and 2000. The IRS raised no issues related to the Section 29 tax credits for these years and issued a "no-change" audit report to AFP's tax matters partner. The IRS is currently auditing Carbontronics for tax years 2000 and 2001. From the inception of Southern Company's investment in these entities through December 31, 2003, Southern Company has recognized through income approximately $274
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million (net of approximately $37 million reserved) in tax credits related to its share of the synthetic fuel production at these entities.
Both entities have private letter rulings from the IRS that concluded significant chemical change occurred based on the procedures and results submitted. In addition, both entities regularly use independentlaboratories and experts to test for chemical change. These tests replicated significant chemical changes consistent with the procedures submitted with the private letter rulings. Southern Company has relied on these private letter rulings and believes that the test results presented in connection with such private letter rulings are valid and that the entities have operated in compliance with their respective private letter rulings and Section 29 of the revenue code. The ultimate outcome of these matters cannot now be determined.
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 through 1999. As part of the audit for the 1996-1999 tax years, the IRS reviewed Southern Company's four international leveraged lease transactions. Based on its review, the IRS proposed to disallow the tax losses associated with one of these transactions, resulting in an additional tax payment of approximately $30 million, including interest. To finalize the audit and eliminate any additional interest charges, Southern Company made this payment to the IRS in May 2003 and filed a refund claim for this amount. On January 5, 2004, the IRS proposed to disallow the refund claim. Southern Company has accounted for the payment as a deposit. Southern Company continues to believe that the transaction remains a valid lease for U.S. tax purposes and, accordingly, intends to file a petition for refund in federal court. If Southern Company is not successful in its defense of the tax treatment for this transaction, it could also affect the timing of the related revenue recognition for book purposes. A cumulative effect adjustment could be required to reduce net income based on the revised cash flows as a result of the changes in the allowed tax deductions.
The IRS did not disallow any tax losses or make any other adjustments for the 1996-1999 period with respect to any of Southern Company's other lease transactions. However, there can be no assurance that subsequent IRS audits would not raise similar disallowance issues. See Note 1 under "Leveraged Leases" for additional information on deferred taxes arising from these transactions. The ultimate outcome of these matters cannot now be determined.
Alabama Power Retail Rate Adjustment Procedures
In November 1982, the Alabama Public Service Commission (APSC) adopted rates that provide for periodic adjustments based upon Alabama Power's earned return on end-of-period retail common equity. The rates also provide for adjustments to recognize the placing of new generating facilities in retail service and for the recovery of retail costs associated with certificated purchased power agreements. Both increases and decreases have been placed into effect since the adoption of these rates. Rate adjustment procedures were revised by the APSC on March 5, 2002. The new procedures provide for periodic rate adjustments annually rather than quarterly and limit any annual adjustment to 3 percent. The return on common equity range of 13 percent to 14.5 percent remained unchanged. The ratemaking procedures will remain in effect until the APSC votes to modify or discontinue them.
In accordance with the Rate Stabilization Equalization plan, a 2 percent increase in retail rates was effective in both April 2002 and October 2001, amounting to an annual increase of $55 million and $58 million, respectively. Also, to recover certificated purchased power costs, an increase of 2.6 percent in retail rates, or $79 million annually, was effective July 2003. An additional increase of $25 million annually is scheduled to be effective in June 2004 for new certificated purchased power costs.
Georgia Power Retail Rate Orders
In December 2001, the GPSC approved a three-year retail rate order for Georgia Power ending December 31, 2004. Retail rates were decreased by $118 million effective January 1, 2002. Under the terms of the order, earnings are evaluated against a retail return on common equity range of 10 percent to 12.95 percent. Two-thirds of any earnings above the 12.95 percent return will be applied to rate refunds, with the remaining one-third retained by Georgia Power. Georgia Power's earnings in both 2002 and 2003 were within the common equity range.
Under a previous three-year order ending December 2001, Georgia Power's earnings were evaluated against a retail return on common equity range of 10 percent to 12.5 percent. The order further provided for $85 million in each year, plus up to $50 million of any earnings above the 12.5 percent return during the second and third years, to be applied to accelerated amortization or depreciation of assets. Two-thirds of additional earnings above the 12.5 percent
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return were applied to rate refunds, with the remaining one-third retained by Georgia Power. Pursuant to the order, Georgia Power recorded $333 million of accelerated amortization and interest thereon, which was credited to a regulatory liability account as mandated by the GPSC.
Under the 2001 rate order, Georgia Power discontinued recording accelerated depreciation and amortization and began amortizing the accumulated balance equally over three years as a credit to expense beginning in 2002. Also, the rate order required Georgia Power to recognize capacity and operating and maintenance costs related to certified purchase power contracts evenly into rates over a three-year period ending December 31, 2004.
Georgia Power is required to file a general rate case on July 1, 2004, in response to which the GPSC would be expected to determine whether the rate order should be continued, modified, or discontinued.
Uncontracted Generating Capacity
On May 21, 2003, Mississippi Power and Southern Power entered into agreements with Dynegy, Inc. (Dynegy) to resolve all outstanding matters related to capacity sales contracts with subsidiaries of Dynegy. Under the terms of the agreements, Dynegy made a cash payment of $75 million to Mississippi Power and $80 million to Southern Power. The contracts between Southern Power and Dynegy were terminated in May 2003, and the Mississippi Power contract was terminated effective October 31, 2003.
The termination payments from Dynegy resulted in a one-time gain to Southern Company of approximately $88 million after tax ($38 million for Mississippi Power and $50 million for Southern Power).
As a result of these contract terminations, Southern Power is completing limited construction activities on Plant Franklin Unit 3 to preserve the long-term viability of the project but has deferred final completion until the 2008-2011 period. The length of the deferral period will depend on forecasted capacity needs and other wholesale market opportunities. As of December 31, 2003, Southern Power's investment in Unit 3 of Plant Franklin was $156 million. Southern Power is continuing to explore alternatives for its existing capacity. The final outcome of these matters cannot now be determined.
Mississippi Power Regulatory Filing
On December 5, 2003, Mississippi Power filed a request with the Mississippi Public Service Commission (MPSC) to modify certain portions of its Performance Evaluation Plan (PEP) and to include 266 megawatts of Plant Daniel units 3 and 4 generating capacity not currently included in jurisdictional cost of service.
As part of Mississippi Power's proposal to include the additional Plant Daniel capacity in retail rates, the MPSC issued an interim accounting order in December 2003 directing Mississippi Power to expense and record in 2003 a regulatory liability in the amount of approximately $60 million while the MPSC fully considers the entire request. However, if the MPSC ultimately denies Mississippi Power's request, the regulatory liability will be required to be reversed.
In the second quarter of 2004, Mississippi Power expects the MPSC to render a final order on the inclusion of the additional Plant Daniel capacity in rates, the amortization period for the regulatory liability, and the requested changes to PEP.
FERC Matters
Southern Power currently has general authorization from the FERC to sell power to nonaffiliates at market-based prices. In addition, each of the retail operating companies has obtained FERC approval to sell power to nonaffiliates at market-based prices under specific contracts. Southern Power and the retail operating companies also have FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities' applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company, and found Southern Company and others to be "pivotal suppliers" in their service areas and ordered the implementation of several mitigation measures. Southern Company and others sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. Southern Company and others submitted comments to the FERC in 2002 regarding these issues. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. Southern Company anticipates that the FERC will address the requests for rehearing in the near future. The final outcome of this matter will depend on the form in which the SMA test and mitigation measures rules may be ultimately adopted and cannot be determined at this time.
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Purchased Power Agreements (PPAs) by Georgia Power and Savannah Electric for Southern Power's Plant McIntosh capacity were certified by the GPSC in December 2002 after a competitive bidding process. In April 2003, Southern Power applied for FERC approval of these PPAs. Interveners opposed the FERC's acceptance of the PPAs, alleging that the PPAs do not meet the applicable standards for market-based rates between affiliates. In July 2003, the FERC accepted the PPAs to become effective as scheduled on June 1, 2005, subject to refund, and ordered that hearings be held to determine: (a) whether, in the design and implementation of the GPSC competitive bidding process, Georgia Power and Savannah Electric unduly preferred Southern Power; (b) whether the analysis of the competitive bids unduly favored Southern Power, particularly with respect to evaluation of non-price factors; (c) whether Georgia Power and Savannah Electric selected their affiliate, Southern Power, based upon a reasonable combination of price and non-price factors; (d) whether Southern Power received an undue preference or competitive advantage in the competitive bidding process as a result of access to its affiliate's transmission system; (e) whether and to what extent the PPAs impact wholesale competition; and (f) whether the PPAs are just and reasonable and not unduly discriminatory. Hearings are scheduled to begin in March 2004. Management believes that the PPAs should be approved by the FERC; however, the ultimate 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 Stanton Unit A and related facilities jointly with the Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency.
At December 31, 2003, 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:
Jointly Owned Facilities --------------------------------------- Percent Amount of Accumulated Ownership Investment Depreciation --------- ---------- ------------- (in millions) Plant Vogtle (nuclear) 45.7% $3,307 $1,706 Plant Hatch (nuclear) 50.1 908 469 Plant Miller (coal) Units 1 and 2 91.8 767 355 Plant Scherer (coal) Units 1 and 2 8.4 115 52 Plant Wansley (coal) 53.5 390 160 Rocky Mountain (pumped storage) 25.4 169 85 Intercession City (combustion turbine) 33.3 12 1 Plant Stanton (combined cycle) Unit A 65.0 155 1 - ----------------------------------------------------------------
Alabama Power, Georgia Power, and Southern Power have contracted to operate and maintain the jointly owned facilities -- except for the Rocky Mountain project 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 Consolidated Statements of Income.
5. Income Taxes
Southern Company files a consolidated federal income tax return. In 2002, Southern Company began filing a combined state of Georgia income tax return. Under a joint consolidated income tax 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.
Mirant was included in the consolidated federal tax return through April 2, 2001. Under the terms of the separation agreement, Mirant will indemnify Southern Company for subsequent assessment of any additional taxes related to its transactions prior to the spin off. The IRS is currently auditing the consolidated tax returns for 2001 and 2000. For additional tax-related information, see Note 3 under "Mirant Bankruptcy" and "Income Tax Issues."
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At December 31, 2003, the tax-related regulatory assets and liabilities were $874 million and $409 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.
Details of income tax provisions are as follows:
2003 2002 2001 - --------------------------------------------------------------- (in millions) Total provision for income taxes: Federal -- Current $130 $284 $477 Deferred 404 167 (10) - --------------------------------------------------------------- 534 451 467 - --------------------------------------------------------------- State -- Current 42 64 103 Deferred 36 13 (12) - --------------------------------------------------------------- 78 77 91 - --------------------------------------------------------------- Total $612 $528 $558 ===============================================================
Net cash payments for income taxes related to continuing operations in 2003, 2002, and 2001 were $188 million, $374 million, and $558 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:
2003 2002 - --------------------------------------------------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $3,737 $3,364 Property basis differences 970 1,011 Other 985 840 - --------------------------------------------------------------- Total 5,692 5,215 - --------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 119 111 Other property basis differences 171 185 Deferred costs 128 188 Pension and other benefits 160 146 Other 483 428 - --------------------------------------------------------------- Total 1,061 1,058 - --------------------------------------------------------------- Total deferred tax liabilities, net 4,631 4,157 Portion included in prepaid expenses (accrued income taxes), net (55) 33 Deferred state tax assets 10 13 - --------------------------------------------------------------- Accumulated deferred income taxes in the Consolidated Balance Sheets $4,586 $4,203 ===============================================================
At December 31, 2003, Southern Company also had available state of Georgia net operating loss carryforward deductions totaling $1.0 billion, which could result in net state income tax benefits of $60 million, if utilized. Less than $27 million of such deductions will expire by 2008; the remainder will expire between 2009 and 2021. During 2003, Southern Company realized $19 million in such state income tax benefits. Beginning in 2002, the state of Georgia allows the filing of a combined return, which should substantially reduce any additional net operating loss carryforwards.
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 Consolidated Statements of Income. Credits amortized in this manner amounted to $29 million in 2003, $27 million in 2002, and $30 million in 2001. At December 31, 2003, all investment tax credits available to reduce federal income taxes payable had been utilized.
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 of subsidiaries, as a result of the following:
2003 2002 2001 - ------------------------------------------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 2.4 2.7 3.7 Synthetic fuel tax credits (5.7) (5.8) (4.2) Employee stock plans dividend deduction (1.5) (2.9) - Non-deductible book depreciation 1.1 1.3 1.7 Difference in prior years' deferred and current tax rate (0.7) (1.0) (1.1) Other (1.5) (0.9) (2.2) - ------------------------------------------------------------- Effective income tax rate 29.1% 28.4% 32.9% =============================================================
6. FINANCING
Mandatorily Redeemable Preferred Securities
Southern Company and the retail operating companies have each 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 and the retail operating companies through the issuance of junior subordinated notes totaling $2.0 billion, which constitute
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NOTES (continued) Southern Company and Subsidiary Companies 2003 Annual Report
substantially all assets of these trusts. Southern Company and the retail operating companies each 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, 2003, preferred securities of $1.9 billion were outstanding and recognized as liabilities in the Consolidated Balance Sheets. Southern Company guarantees the notes related to $555 million of these securities issued on its behalf.
Securities Due Within One Year
A summary of scheduled maturities and redemptions of long-term debt due within one year at December 31 is as follows:
2003 2002 - --------------------------------------------------------------- (in millions) First mortgage bond maturities and redemptions $ - $ 33 Pollution control bonds - 1 Capitalized leases 11 11 Senior notes 655 1,552 Mandatorily redeemable preferred securities 40 40 Other long-term debt 35 42 - --------------------------------------------------------------- Total $741 $1,679 ===============================================================
Debt redemptions and/or serial maturities through 2008 applicable to total long-term debt are as follows: $741 million in 2004; $891 million in 2005; $951 million in 2006; $975 million in 2007; and $473 million in 2008.
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. The subsidiary companies' mortgages, which secure the first mortgage bonds issued by the retail operating companies, constitute a direct first lien on substantially all of the retail operating companies' respective fixed property and franchises. Georgia Power discharged its mortgage in 2002 and the lien was removed. 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 2004, unused credit arrangements with banks totaled $3.5 billion, of which $2.8 billion expires during 2004 and $670 million expires during 2005 and beyond. The following table outlines the credit arrangements by company:
Amount of Credit ------------------------------------ Expires -------------- 2005 & Company Total Unused 2004 beyond - ------- -------------------------------------- (in millions) Alabama Power $ 865 $ 865 $ 865 $ - Georgia Power 725 725 725 - Gulf Power 56 56 56 - Mississippi Power 100 100 100 - Savannah Electric 80 60 40 20 Southern Company 1,000 1,000 1,000 - Southern Power 650 650 - 650 Other 20 20 20 - - ---------------------------------------------------------------- Total $3,496 $3,476 $2,806 $670 ================================================================
Approximately $2.25 billion of the credit facilities expiring in 2004 allow the execution of term loans for an additional two-year period, and $265 million allow execution of one-year term loans. Most of these agreements include stated borrowing rates but also allow for competitive bid loans.
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 less than 1/8 of 1 percent for Southern Company and the retail operating companies and less than 3/8 of 1 percent for Southern Power. Compensating balances are not legally restricted from withdrawal. Included in the total $3.5 billion of unused credit arrangements is $2.8 billion of syndicated credit arrangements that require the payment of agent fees.
Most of Southern Company's, Southern Power's, and the retail operating companies' credit arrangements with banks have covenants that limit debt levels to 65 percent of total capitalization, as defined in the agreements. Exceeding these debt levels would result in a default under the credit arrangements At December 31, 2003, Southern Company, Southern Power, and the retail operating companies were 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. Under the credit arrangements for Southern Company and the retail operating companies, the cross default provisions are restricted only to the indebtedness, including any guarantee obligations, of the company that has the credit arrangement with the bank. For Southern Power's bank credit arrangements, there is a cross default to Southern Company's indebtedness, which
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NOTES (continued) Southern Company and Subsidiary Companies 2003 Annual Report
if triggered would require prepayment of debt related to projects financed under the credit arrangement that are not complete. Southern Company has committed to fund at least 35 percent on Southern Power's construction project financing and to pay for construction overruns to the extent that Southern Power's cash flow is insufficient. Southern Company and its subsidiaries are currently in compliance with all such covenants. Borrowings under certain retail operating companies' unused credit arrangements totaling $50 million would be prohibited if the borrower experiences a material adverse change, as defined in such agreements. Initial borrowings for new projects under Southern Power's credit facility would be prohibited if Southern Power or Southern Company experiences a material adverse change, as defined in that credit facility.
A portion of the $3.5 billion unused credit with banks is allocated to provide liquidity support to the companies' variable rate pollution control bonds. The amount of variable rate pollution control bonds requiring liquidity support as of December 31, 2003, was $659 million.
Southern Company, the retail operating companies, and Southern Power borrow through commercial paper programs that have the liquidity support of committed bank credit arrangements. In addition, Southern Company and the retail operating companies from time to time borrow through extendible commercial note programs. As of December 31, 2003, no extendible commercial notes were outstanding. The amount of commercial paper outstanding at December 31, 2003, and December 31, 2002, was $568 million and $858 million, respectively. During 2003, the peak amount outstanding for commercial paper was $1.66 billion, and the average amount outstanding was $900 million. The average annual interest rate on commercial paper was 1.3 percent in 2003. Commercial paper is included in notes payable on the Consolidated Balance Sheets.
Financial Instruments
The retail operating companies, Southern Power, and Southern Company GAS enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the retail 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 shift substantially all fuel cost responsibility to the purchaser. Each of the retail operating companies has implemented fuel-hedging programs at the instruction of their respective public service commissions. Together with Southern Power, the retail operating companies may enter into hedges of forward electricity sales. Southern Company GAS has gas-hedging programs to substantially mitigate its exposure to price volatility for its gas purchases.
At December 31, 2003, the fair value of derivative energy contracts was reflected in the financial statements as follows:
Amounts - --------------------------------------------------------------- (in millions) Regulatory liabilities, net $14.9 Other comprehensive income 1.5 Net income (0.6) - --------------------------------------------------------------- Total fair value $15.8 ===============================================================
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. For Southern Power and Southern Company GAS, the fair value gains or losses for cash flow hedges are recorded in other comprehensive income and are reclassified into earnings at the same time the hedged items affect earnings. For the year 2003, approximately $22 million of pre-tax gains were reclassified from other comprehensive income to fuel expense. For the year 2004, approximately $5 million of pre-tax gains are expected to be reclassified from other comprehensive income to fuel expense.
Southern Company and certain subsidiaries also enter into derivatives to hedge exposure to interest rate changes. 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 are generally structured to match the critical terms of the hedged debt instruments; therefore, no material ineffectiveness has been recorded in earnings.
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NOTES (continued) Southern Company and Subsidiary Companies 2003 Annual Report
At December 31, 2003, Southern Company had $3.0 billion notional amount of interest rate swaps outstanding with net fair value gains of $33 million as follows:
Fair Value Hedges Variable Fair Rate Notional Value Company Maturity Paid Amount Gain - ------------------------------------------ ------------------ (in millions) Southern Company 2007 6-month $400 $30.9 LIBOR - 0.10% 2009 6-month $40 $0.8 LIBOR + 2.92% - ---------------------------------------------------------------
Cash Flow Hedges Weighted Average Fair Fixed Value Rate Notional Gain/ Company Maturity Paid Amount (Loss) - ------------------------------------------ ------------------ (in millions) Southern Company 2004 3.20% $200 $(2.0) Alabama Power 2004 1.63* 486 (0.2) 2006 1.89 195 1.5 2007 1.99* 486 4.4 Georgia Power 2004 1.39* 873 (0.8) 2005 1.56 50 - 2005 1.96 250 (1.1) Savannah Electric 2004 2.06 20 (0.1) - ------------------------------------------------------------------ *Hedged using the Bond Market Association Municipal Swap Index.
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 2003 and 2002, the company recognized losses of $116 million and $14 million, respectively, upon termination of certain interest derivatives at the same time it issued debt. These losses have been deferred in other comprehensive income and will be amortized to interest expense over the life of the related debt. For 2003, approximately $26 million of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2004, pre-tax losses of approximately $22 million are expected to be reclassified from other comprehensive income to interest expense.
7. COMMITMENTS
Construction Program
Southern Company is engaged in continuous construction programs, currently estimated to total $2.2 billion in 2004, $2.2 billion in 2005, and $2.6 billion in 2006. These amounts include $41 million, $31 million, and $27 million in 2004, 2005, and 2006, respectively, for construction expenditures related to contractual purhase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included in this note 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 regulations; changes in existing nuclear plants to meet new regulatory requirements; changes in FERC rules and transmission regulations; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2003, significant purchase commitments were outstanding in connection with the construction program. Southern Company has approximately 1,200 megawatts of additional generating capacity scheduled to be placed in service by 2005. In addition, capital improvements to generation, transmission, and distribution facilities -- including those to meet environmental standards -- will continue.
Long-Term Service Agreements
The retail operating companies and Southern Power have entered into several Long-Term Service Agreements (LTSAs) with General Electric (GE) for the purpose of securing maintenance support for the combined cycle and combustion turbine generating facilities owned by the subsidiaries. In summary, the LTSAs stipulate 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, except for Southern Power's Plant Dahlberg, these LTSAs are in effect through two major inspection cycles per unit. The Dahlberg agreement is in effect through the first major inspection of each unit. Scheduled payments to GE are made at various intervals based on actual operating hours of the
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respective units. Total payments to GE under these agreements for facilities owned are currently estimated at $1.3 billion over the remaining life of the agreements, which may range up to 30 years. However, the LTSAs contain various cancellation provisions at the option of the purchasers.
Payments made to GE prior to the performance of any planned inspections are recorded as a prepayment in the Consolidated Balance Sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed.
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. Natural gas purchase commitments contain given volumes with prices based on various indices at the time of delivery. Amounts included in the chart below represent estimates based on New York Mercantile future prices at December 31, 2003. Also, Southern Company has entered into various long-term commitments for the purchase of electricity. Total estimated minimum long-term obligations at December 31, 2003 were as follows:
Coal and Natural Nuclear Purchased Year Gas Fuel Power - ------------------------------------------------------------ (in millions) 2004 $ 814 $2,409 $ 139 2005 538 1,723 174 2006 491 1,475 181 2007 350 1,131 183 2008 269 544 184 2009 and thereafter 2,763 182 918 - ------------------------------------------------------------ Total commitments $5,225 $7,464 $1,779 ============================================================
Additional commitments for fuel will be required to supply Southern Company's future needs.
Operating Leases
In May 2001, Mississippi Power began the initial 10-year term of a lease agreement signed in 1999 for a combined cycle generating facility built at Plant Daniel. The facility cost 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 percent of Juniper's assets. In accordance with FASB Interpretation No. 46, Mississippi Power is not required to consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease under FASB Statement No. 13. 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 $369 million. Mississippi Power is required to amortize approximately four percent 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 calls for Mississippi Power to amortize an additional 17 percent 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 percent 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. Mississippi Power has recognized in the balance sheet a liability of approximately $15 million for the fair market value of this residual value guarantee. In 2003, approximately $11 million in lease termination costs were included in operation expenses and $26 million in lease expense. The amount of future minimum operating lease payments will be approximately $29 million annually during the initial term.
Southern Company has other operating lease agreements with various terms and expiration dates. Total operating lease expenses were $156 million, $171 million, and $64 million for 2003, 2002, and 2001, respectively. At December 31, 2003, estimated minimum rental commitments for noncancelable operating leases were as follows:
Rail Year Cars Other Total - ---- ---------------------------- (in millions) 2004 $ 36 $ 92 $128 2005 33 80 113 2006 28 67 95 2007 19 57 76 2008 19 48 67 2009 and thereafter 106 156 262 - --------------------------------------------------------------- Total minimum payments $241 $500 $741 ===============================================================
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NOTES (continued) Southern Company and Subsidiary Companies 2003 Annual Report
For the retail operating companies, the 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 rail car leases with respect to the residual value of the leased property. These leases expire in 2004, 2006, and 2010, and the maximum obligations are $39 million, $66 million, and $40 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
Southern Company has made separate guarantees to certain counterparties regarding performance of contractual commitments by Mirant's trading and marketing subsidiaries. At December 31, 2003, the total notional amount of guarantees outstanding was less than $30 million, all of which will expire by 2009. Under the terms of the separation agreement, Mirant may not enter into any new commitments under these guarantees after the spin off date and must use reasonable efforts to release Southern Company from all such support arrangements and indemnify Southern Company for any obligations incurred. Subsequent to the spin off, Mirant began paying Southern Company a fee of 1 percent annually on the average aggregate maximum principal amount of all guarantees outstanding until they are replaced or expire. However, in December 2003, Mirant notified Southern Company that the Bankruptcy Code provides relief from paying this fee.
Southern Company has executed a keep-well agreement with a subsidiary of Southern Holdings to make capital contributions in the event of any shortfall in payments due under a participation agreement with an entity in which the subsidiary holds a 30 percent investment. The maximum aggregate amount of Southern Company's liability under this keep-well agreement is $50 million.
As discussed earlier in this note under "Operating Leases," Alabama Power, Georgia Power, and Mississippi Power have entered into certain residual value guarantees. Also, Southern Company has certain contingent liabilities as discussed in Note 3 under "Mobile Energy Services' Petition for Bankruptcy."
8. COMMON STOCK
Stock Issued
Southern Company raised $470 million or 18 million shares in 2003 and $378 million or 16 million shares in 2002 from the issuance of new common shares under the company's various stock plans. Southern Company issued 2 million and 17 million treasury shares of common stock in 2002 and 2001, respectively, through various company stock plans. Proceeds from the issuance of treasury stock were $56 million in 2002 and $395 million in 2001.
Shares Reserved
At December 31, 2003, a total of 60 million shares was 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, 2003, 6,202 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 55 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors
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NOTES (continued) Southern Company and Subsidiary Companies 2003 Annual Report
in accordance with the plan. Stock option data for the plan has been adjusted to reflect the Mirant spin off. Activity from 2001 to 2003 for the plan is summarized below:
Shares Average Subject Option Price To Option Per Share - --------------------------------------------------------------- Balance at December 31, 2000 22,566,627 $14.92 Options granted 13,623,210 20.31 Options canceled (3,397,152) 15.39 Options exercised (3,161,800) 13.83 - --------------------------------------------------------------- Balance at December 31, 2001 29,630,885 17.46 Options granted 8,040,495 25.28 Options canceled (104,212) 19.64 Options exercised (4,892,354) 15.16 - --------------------------------------------------------------- Balance at December 31, 2002 32,674,814 19.72 Options granted 7,165,452 27.98 Options canceled (183,038) 24.35 Options exercised (5,725,336) 16.56 - --------------------------------------------------------------- Balance at December 31, 2003 33,931,892 $21.97 ===============================================================
Shares reserved for future grants: At December 31, 2001 54,795,653 At December 31, 2002 46,788,994 At December 31, 2003 39,752,039 - --------------------------------------------------------------- Options exercisable: At December 31, 2001 11,965,858 At December 31, 2002 15,463,414 At December 31, 2003 18,872,769 - ---------------------------------------------------------------- The following table summarizes information about options outstanding at December 31, 2003:
Dollar Price Range of Options --------------------------- 13-19 19-25 25-30 - --------------------------------------------------------------- Outstanding: Shares (in thousands) 7,428 11,719 14,785 Average remaining life (in years) 4.7 6.2 8.3 Average exercise price $15.32 $20.39 $26.57 Exercisable: Shares (in thousands) 7,428 8,303 3,142 Average exercise price $15.32 $20.40 $25.49 - ---------------------------------------------------------------
The estimated fair values of stock options granted in 2003, 2002, and 2001 were derived using the Black-Scholes stock option pricing model. The following table shows the assumptions and the weighted average fair values of stock options:
2003 2002 2001 - --------------------------------------------------------------- Interest rate 2.7% 2.8% 4.8% Average expected life of stock options (in years) 4.3 4.3 4.3 Expected volatility of common stock 23.6% 26.3% 25.4% Expected annual dividends on common stock $1.37 $1.34 $1.34 Weighted average fair value of stock options granted $3.59 $3.37 $2.82 - ---------------------------------------------------------------
The pro forma impact of fair-value accounting for options granted on earnings from continuing operations is as follows: As Pro Reported Forma - --------------------------------------------------------------- Net income (in millions) $1,474 $1,456 Earnings per share (dollars): Basic $2.03 $2.00 Diluted $2.02 $1.99 Net income (in millions) $1,318 $1,299 Earnings per share (dollars): Basic $1.86 $1.83 Diluted $1.85 $1.82 Net income (in millions) $1,119 $1,102 Earnings per share (dollars): Basic $1.62 $1.60 Diluted $1.61 $1.59 - ---------------------------------------------------------------
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:
Average Common Stock Shares ------------------------------- 2003 2002 2001 - --------------------------------------------------------------- (in thousands) As reported shares 726,702 708,161 689,352 Effect of options 5,202 5,409 4,191 - --------------------------------------------------------------- Diluted shares 731,904 713,570 693,543 ===============================================================
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NOTES (continued) Southern Company and Subsidiary Companies 2003 Annual Report
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2003, consolidated retained earnings included $3.9 billion of undistributed retained earnings of the subsidiaries. Of this amount, $313 million was restricted against the payment by the subsidiary companies of cash dividends on common stock under terms of bond indentures.
In accordance with the PUHCA, the subsidiaries are also restricted from paying common dividends from paid-in capital without SEC approval.
9. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988, 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 $10.9 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 $10 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 $20 million per company to be paid for each incident in any one year. The Price-Anderson Amendments Act expired in August 2002; however, the indemnity provisions of the act remain in place for commercial nuclear reactors.
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 $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.
NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After this deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. 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.
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 $36 million and $40 million, respectively.
Following the terrorist attacks of September 2001, both ANI and NEIL confirmed that terrorist acts against commercial nuclear power plants would be covered under their insurance. Both companies, however, revised their policy terms on a prospective basis to include an industry aggregate for all "non-certified" terrorist acts, i.e., acts that are not certified acts of terrorism pursuant to the Terrorism Risk Insurance Act of 2002 (TRIA). The NEIL aggregate -- applies to non-certified claims stemming from terrorism within a 12-month duration -- is $3.24 billion plus any amounts available through reinsurance or indemnity from an outside source. The non-certified ANI cap is a $300 million shared industry aggregate. Any act of terrorism that is certified pursuant to the TRIA will not be subject to the foregoing NEIL and ANI limitations but will be subject to the TRIA annual aggregate limitation of $100 billion of insured losses arising from certified acts of terrorism. The TRIA will expire on December 31, 2005.
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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NOTES (continued) Southern Company and Subsidiary Companies 2003 Annual Report
10. SEGMENT AND RELATED INFORMATION
Southern Company's reportable business segment is the sale of electricity in the Southeast by the five retail operating companies and Southern Power. Net income and total assets for discontinued operations are included in the reconciling eliminations column. 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, energy-related services, and natural gas marketing. Intersegment revenues are not material. Financial data for business segments and products and services are as follows:
Business Segments
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ALABAMA POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Alabama Power Company 2003 Annual Report
The management of Alabama Power Company has prepared -- and is responsible for - -- the financial statements and related information included in this report. These statements were prepared in accordance with accounting principles generally accepted in the United States and necessarily include amounts that are based on the best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that the accounting records reflect only authorized transactions of the Company. Limitations exist in any system of internal controls, however, based on a recognition that the cost of the system should not exceed its benefits. The Company believes its system of internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's internal accounting controls are evaluated on an ongoing basis by the Company's internal audit staff. The Company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements.
Southern Company's audit committee of its board of directors, composed of four independent directors, provides a broad overview of management's financial reporting and control functions. Additionally, the controls and compliance committee of Alabama Power's board of directors, composed of three outside directors, meets periodically with management, the internal auditors, and the independent public accountants to discuss auditing, internal controls, and compliance matters. The internal auditors and independent public accountants have access to the members of these committees at any time.
Management believes that its policies and procedures provide reasonable assurance that the Company's operations are conducted according to a high standard of business ethics.
In management's opinion, the financial statements present fairly, in all material respects, the financial position, results of operations and cash flows of Alabama Power Company in conformity with accounting principles generally accepted in the United States.
/s/Charles D. McCrary Charles D. McCrary President and Chief Executive Officer
/s/William B. Hutchins, III William B. Hutchins, III Executive Vice President, Chief Financial Officer, and Treasurer
March 1, 2004
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INDEPENDENT AUDITORS' REPORT
Alabama Power Company:
We have audited the accompanying balance sheets and statements of capitalization of Alabama Power Company (a wholly owned subsidiary of Southern Company) as of December 31, 2003 and 2002, and the related statements of income, comprehensive income, common stockholder's equity, and cash flows for the years then ended. These financial statements are the responsibility of Alabama Power Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The financial statements of Alabama Power Company for the year ended December 31, 2001 were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements and included an explanatory paragraph that described a change in the method of accounting for derivative instruments and hedging activities in their report dated February 13, 2002.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, the financial statements (pages II-83 to II-105) present fairly, in all material respects, the financial position of Alabama Power Company at December 31, 2003 and 2002, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the financial statements, in 2003 Alabama Power Company changed its method of accounting for asset retirement obligations.
/s/Deloitte & Touche LLP Birmingham, Alabama March 1, 2004
THE FOLLOWING REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH THE COMPANY'S 2001 ANNUAL REPORT AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP. SEE EXHIBIT 23(b)2 FOR ADDITIONAL INFORMATION.
To Alabama Power Company:
We have audited the accompanying balance sheets and statements of capitalization of Alabama Power Company (an Alabama corporation and a wholly owned subsidiary of Southern Company) as of December 31, 2001 and 2000, and the related statements of income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2001. 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 auditing standards generally accepted in the 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, the financial statements (pages II-58 through II-76) referred to above present fairly, in all material respects, the financial position of Alabama Power Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
As explained in Note 1 to the financial statements, effective January 1, 2001, Alabama Power Company changed its method of accounting for derivative instruments and hedging activities.
/s/Arthur Andersen LLP Birmingham, Alabama February 13, 2002
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Alabama Power Company 2003 Annual Report
OVERVIEW OF EARNINGS AND BUSINESS - ---------------------------------- ACTIVITIES - ------------
Earnings
Alabama Power Company's 2003 net income after dividends on preferred stock was $473 million, representing a $12 million (2.5 percent) increase from the prior year. This improvement is due primarily to higher sales for resale, increases in other revenues, and lower interest expense, partially offset by higher non-fuel operating expenses.
In 2002, earnings were $461 million, representing a 19.3 percent increase from the prior year. This improvement was primarily attributable to increased territorial energy sales and higher retail rates when compared to the prior year. More favorable weather conditions in 2002 as compared to the unusually mild weather experienced in 2001 contributed to the increases in territorial sales. The increases in revenues were partially offset by increased non-fuel operating expenses. Earnings in 2001 were $387 million, representing a 7.9 percent decrease from the prior year. This decline was primarily attributable to a decrease in territorial energy sales as a result of an economic downturn and milder temperatures.
The return on average common equity for 2003 was 13.75 percent compared to 13.80 percent in 2002 and 11.89 percent in 2001.
Business Activities
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.
Several factors affect the opportunities, challenges, and risk of the Company's primary business of selling electricity. These factors include the ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stricter environmental standards. 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 elasticity of demand, and the rate of economic growth in the service area.
RESULTS OF OPERATIONS - ---------------------
A condensed income statement is as follows:
Increase (Decrease) Amount From Prior Year - ---------------------------------------------------------------- 2003 2003 2002 2001 - ---------------------------------------------------------------- (in millions) Operating revenues $3,960 $250 $124 $(81) - ---------------------------------------------------------------- Fuel 1,068 98 (31) 38 Purchased power 315 66 (44) (56) Other operation and maintenance 921 67 71 (56) Depreciation and amortization 413 15 15 19 Taxes other than income taxes 228 11 2 5 - ---------------------------------------------------------------- Total operating expenses 2,945 257 13 (50) - ---------------------------------------------------------------- Operating income 1,015 (7) 111 (31) Other income (expense), net (252) 17 7 (15) Less -- Income taxes 290 (2) 44 (13) - ---------------------------------------------------------------- Net Income $ 473 $ 12 $ 74 $(33) ================================================================
Revenues
Operating revenues for 2003 were nearly $4.0 billion, reflecting a $250 million increase from 2002. The following table summarizes the principal factors that have affected operating revenues for the past three years:
Amount - ------------------------------------------------------------------ 2003 2002 2001 - ------------------------------------------------------------------ (in millions) Retail -- prior year $2,951 $2,748 $2,953 Change in - Base rates 51 76 23 Sales growth 68 70 (36) Weather (61) 60 (62) Fuel cost recovery and other 42 (3) (130) - ------------------------------------------------------------------ Retail -- current year 3,051 2,951 2,748 - ------------------------------------------------------------------ Sales for resale -- Non-affiliates 488 474 486 Affiliates 277 188 245 - ------------------------------------------------------------------ Total sales for resale 765 662 731 - ------------------------------------------------------------------ Other operating revenues 144 97 107 - ------------------------------------------------------------------ Total operating revenues $3,960 $3,710 $3,586 ================================================================== Percent change 6.7% 3.5% (2.2)% - ------------------------------------------------------------------
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2003 Annual Report
Retail revenues in 2003 were $3.1 billion. Revenues increased $100 million (3.4 percent) from the prior year, increased $203 million (7.4 percent) in 2002, and decreased $205 million (6.9 percent) in 2001. All sectors of retail revenues increased for the Company in 2003 primarily due to increased fuel revenue and a 2.6 percent increase in retail base rates which went into effect in July 2003. See Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for additional information.
The primary contributors to the increase in revenues in 2002, shown in the table above, were the positive effect of favorable weather conditions on energy sales and increases in retail base rates (0.6 percent increase in July 2001 and 2 percent increases in both October 2001 and April 2002). The Company mitigated the effect of these increases to customers with a decrease to the energy cost recovery factor in April 2002.
The revenue decrease in 2001 was primarily due to the negative impact of milder temperatures on energy sales and an economic downturn in the Company's service territory.
Fuel rates billed to customers are designed to fully recover fluctuating fuel costs over a period of time. At December 31, 2003, the Company had no unrecovered fuel costs. Fuel revenues have no effect on net income because they represent the recording of revenues to offset fuel expenses.
Sales for resale to non-affiliates are predominantly unit power sales under long-term contracts to Florida utilities. Revenues from power sales contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. These capacity and energy components of the unit power contracts were as follows:
2003 2002 2001 ------------------------------------ (in thousands) Unit power - Capacity $130,022 $119,193 $124,720 Energy 145,342 134,051 134,006 --------------------------------------------------- ----------- Total $275,364 $253,244 $258,726 ===============================================================
There are no significant scheduled declines in unit power sales capacity until the termination of the unit power sales contracts in 2010.
Short-term opportunity energy sales are also included in sales for resale to non-affiliates. These opportunity sales are made at market rates that generally include the recovery of fixed costs and a return, in addition to the variable energy cost. Revenues associated with other power sales to non-affiliates were as follows:
2003 2002 2001 -------------------------------- (in thousands) Other power sales - Capacity and other $33,858 $14,613 $ 13,324 Variable cost of energy 44,627 61,925 91,608 ---------------------------------------------------- ---------- Total $78,485 $76,538 $104,932 ===============================================================
Revenues from sales to affiliated companies within the Southern electric system, as well as purchases of energy, will vary from year to year depending on demand and the availability and cost of generating resources at each company. Sales for resale revenues increased $26.6 million in 2003 due to increased capacity payments received in accordance with the affiliated company interchange agreements as a result of increased capacity. Excluding the capacity revenues, these transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through the Company's energy cost recovery clause.
Other operating revenues in 2003 increased $47 million (48.6 percent) from 2002 due to an increase of $19.4 million in revenues from gas-fueled co-generation steam facilities -- primarily as a result of higher gas prices -- and a $14.8 million increase in revenues from Alabama Public Service Commission (Alabama PSC) approved fees charged to customers for connection, reconnection, and collection when compared to the same period in 2002. Since co-generation steam revenues are generally offset by fuel expenses, these revenues did not have a significant impact on earnings.
The $11 million (9.9 percent) decrease in other operating revenues in 2002 resulted primarily from a $7.0 million decrease in revenues from gas-fueled co-generation steam facilities due to lower gas prices and lower demand. The $21 million (23.9 percent) increase in 2001 was primarily attributed to a $6.4 million increase in steam sales in conjunction with the operation of the Company's co-generation facilities, a $5.3 million increase in fuel sales, and a $5.1 million increase in rent from electric property.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2003 Annual Report
Energy Sales
Changes in revenues are influenced heavily by the volume of energy sold each year. Kilowatt-hour (KWH) sales for 2003 and the percent change by year were as follows:
KWH Percent Change ---------------------------------------- 2003 2003 2002 2001 ---------------------------------------- (millions)
Residential 16,960 (2.5)% 9.6% (5.3)% Commercial 13,452 0.7 4.4 (1.5) Industrial 21,593 2.3 3.1 (7.4) Other 203 (1.1) 3.7 (3.9) ---------- Total retail 52,208 0.3 5.5 (5.2) Sales for resale - Non-affiliates 17,086 9.9 1.8 2.9 Affiliates 9,422 6.5 - 64.7 ---------- Total 78,716 2.9 4.1 1.6 - ---------------------------------------------------------------
Residential energy sales for 2003 experienced a 2.5 percent decrease over the prior year and total retail energy sales grew by 0.3 percent primarily as a result of milder-than-normal summer temperatures compared to the previous year. Although retail sales to industrial customers increased 2.3 percent in 2003 and 3.1 percent in 2002, overall sales to industrial customers remained depressed due to the continuing effect of sluggish economic conditions.
Residential energy sales for 2002 experienced a 9.6 percent increase over the prior year and total retail energy sales grew by 5.5 percent primarily as a result of warmer summer temperatures and colder winter weather conditions compared to the previous year.
The decrease in 2001 retail energy sales was primarily due to milder temperatures and an economic downturn in the Company's service area. This was offset by an increase in sales for resale to affiliates. Increased operation of the Company's combined cycle facilities due to lower natural gas prices and an increase in the Company's combined cycle capacity contributed to the increase in sales for resale.
Assuming normal weather, sales to retail customers are projected to grow approximately 1.7 percent annually on average during 2004 through 2008.
Expenses
The total operating expenses in 2003 were approximately $3.0 billion, an increase of $257 million (9.6 percent) over the previous year. This increase is mainly due to a $98 million increase in fuel expense primarily related to an increase in the average cost of natural gas and coal. In addition, purchased power expenses increased a total of $66 million, maintenance expense increased $30 million primarily related to transmission and distribution overhead lines, and depreciation and amortization expense increased $15 million.
In 2002, total operating expenses of $2.7 billion increased by $13 million (0.5 percent) over the previous year. This slight increase was mainly due to a $35 million increase in administrative and general expenses primarily related to employee salaries, insurance expense, and accrued expenses for liability insurance, litigation and workers compensation, a $19 million increase in production expenses related to boiler plant maintenance, and a $15 million increase in depreciation and amortization expenses due to an increase in depreciable property. These increases were offset by a $43 million decrease in purchased power expenses and a $14 million decrease in fuel expenses related to lower coal prices.
In 2001, total operating expenses of $2.7 billion were down $50 million (1.8 percent) compared with 2000. This decline was mainly due to an $18 million net decrease in fuel and purchased power costs related to lower fuel prices, increased hydro generation and added capacity. The Company also had a $56 million decrease in non-production operation and maintenance expense related to settlements received in connection with the Company's insurance program, lower costs related to services provided by Southern Company Services (SCS) and Southern Nuclear Operating Company, and a reduction to the natural disaster reserve accrual. These decreases in expense were partially offset by a $19 million increase in depreciation and amortization due to an increase in depreciable property.
Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of fossil and nuclear generating units and hydro generation. The amount and sources of generation and the average cost of fuel per net KWH generated and the average cost of purchased power were as follows:
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2003 Annual Report
-------------------------- 2003 2002 2001 -------------------------- Total generation (billions of KWHs) 72 71 68 Sources of generation (percent) -- Coal 64 62 64 Nuclear 19 19 18 Hydro 8 6 6 Gas 9 13 12 Average cost of fuel per net kilowatt-hour generated (cents) 1.67 1.47 1.56 Average cost of purchased power per net kilowatt-hour (cents) 3.56 2.91 3.28 - --------------------------------------------------------------
In 2003, total fuel and purchased power expenses of $1.4 billion increased $164 million (13.4 percent) over 2002 due to a 58.3 percent increase in average gas prices and a 2.2 percent increase in average coal prices. Fuel and purchased power expenses in 2002 of $1.2 billion decreased $75 million (5.8 percent) due primarily to lower average fuel cost, while total energy sales increased 3.0 billion kilowatt hours (4.1 percent) compared with the amounts recorded in 2001. Fuel and purchased power expenses in 2001 decreased $18 million (1.4 percent) compared to 2000 because of reduced generation due to milder temperatures in 2001. Fuel expenses, including purchased power, are offset by fuel revenues through the Company's energy cost recovery clause and have no effect on net income.
Purchased power consists of purchases from affiliates in the Southern electric system and non-affiliated companies. Purchased power transactions among the Company and its affiliates will vary from period to period depending on demand, the availability, and the variable production cost of generating resources at each company. In 2003, purchased power from non-affiliates increased $20 million (22 percent) due to a 19.3 percent increase in price and a 9.5 percent increase in energy purchased when compared to 2002. During 2002, purchased power transactions from non-affiliates decreased $54 million (37 percent) due to the addition in May 2001 of a combined cycle unit which generated 6.1 billion kilowatt hours in 2002, an 18.4 percent increase over the previous year. Purchased power transactions from non-affiliates also declined in 2001 because of the addition of the combined cycle unit and an increase in hydro generation resulting in a $20 million (12 percent) decline from the year 2000.
Depreciation and amortization expense increased 3.6 percent in 2003, 3.9 percent in 2002, and 5.2 percent in 2001. These increases reflect additions to property, plant, and equipment.
Allowance for Equity Funds Used During Construction (AFUDC) increased $1.4 million (12.8 percent) in 2003 due to an increase in the applicable AFUDC rate. AFUDC increased $4 million (57.5 percent) in 2002 due to an increase in the amount of construction work in progress over the prior year. AFUDC decreased $16 million (68.9 percent) in 2001 due to completing construction of Plant Barry Unit 7 and placing it in service in May 2001.
Interest expense, net of amounts capitalized, of $214 million in 2003 decreased $11.4 million (5.1 percent) from 2002, which had decreased $21 million (8.4 percent) from 2001. Both years reflect a decrease in interest rates on long-term debt due to refinancing activities. Interest expense increased $11 million (4.7 percent) in 2001 compared to 2000.
Effects of Inflation
The Company is subject to rate regulation that is based on the recovery of historical costs. In addition, the income tax laws are also based on historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that 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 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 and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed.
Future Earnings Potential
General
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. Major factors include the ability of the Company to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stricter environmental standards. Growth in energy sales is
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2003 Annual Report
subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price elasticity of demand, and the rate of economic growth in the Company's service area.
Industry Restructuring
The Company operates as a vertically integrated utility providing electricity to customers within its traditional service area located in the State of Alabama and to wholesale customers in the Southeast.
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 Policy Act of 1992 (Energy Act). The Energy Act allowed independent power producers to access a utility's transmission network and sell electricity to other utilities.
Although the Energy Act does not provide for retail customer access, it was a major catalyst for restructuring and consolidations that took place within the utility industry. Numerous federal and state initiatives that promote wholesale and retail competition are in varying stages. Among other things, these initiatives allow retail customers in some states to choose their electricity provider. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While various restructuring and competition initiatives have been discussed in Alabama, none have been enacted. In October 2000, the Alabama PSC completed a two-year study of electric industry restructuring, concluding that (i) restructuring of the electric utility industry in Alabama was not in the public interest and (ii) the Alabama PSC itself could not mandate retail competition or electric industry restructuring without enabling state legislation. Electric utility restructuring could require numerous issues to be resolved, including significant ones relating to recovery of any stranded investments, full cost recovery of energy produced, and other issues related to the energy crisis that occurred in California as well as the August 2003 power outage in the Northeast.
Since 2001, merchant energy companies and traditional electric utilities with significant energy marketing and trading activities have come under severe financial pressures. Many of these companies have completely exited or drastically reduced all energy marketing and trading activities and sold foreign and domestic electric infrastructure assets. The Company has not experienced any material adverse financial impact regarding its limited energy trading operations through SCS.
Continuing to be a low-cost producer could provide opportunities to increase the size and profitability in markets that evolve with changing regulation and competition. Conversely, future regulatory changes could adversely affect the Company's growth, and if the Company does not remain a low-cost producer and provide quality service, then energy sales growth could be limited, and this could significantly erode earnings.
Environmental Matters
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action against the Company alleging that the Company had violated the New Source Review (NSR) provisions of the Clean Air Act with respect to coal-fired generating facilities at the Company's Plants Miller, Barry, and Gorgas. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The action against the Company has been stayed since the spring of 2001 during the appeal of a very similar NSR action against the Tennessee Valley Authority before the U.S. Court of Appeals for the Eleventh Circuit. The Eleventh Circuit appeal was decided on September 16, 2003, and, on February 13, 2004, the EPA petitioned the U.S. Supreme Court to review the Eleventh Circuit's decision. The EPA also filed a motion to lift the stay in the action against the Company. See Note 3 to the financial statements under "New Source Review Actions" for additional information.
In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. The December 2002 revisions included changes to the regulatory exclusions and the methods of calculating emissions increases. The October 2003 regulations clarified the scope of the existing Routine Maintenance, Repair, and Replacement exclusion. A coalition of states and environmental organizations filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. On December 24, 2003, the Court of Appeals granted a stay of the October 2003 revisions
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2003 Annual Report
pending its review of the rules and ordered that its review be conducted on an expedited basis. In January 2004, the Bush Administration announced that it would continue to enforce the existing rules until the courts resolve legal challenges to the EPA's revised NSR regulations. In any event, the final regulations must be adopted by the State of Alabama in order to apply to the Company's facilities. The effect of these final regulations and the related legal challenges cannot be determined at this time.
The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome in this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
Environmental Statutes and Regulations
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. Compliance with these environmental requirements will involve significant costs - -- both capital and operating -- a major portion of which is expected to be recovered through existing ratemaking provisions. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under "Capital Requirements and Contractual Obligations." There is no assurance, however, that all such costs will, in fact, be recovered.
Compliance with the federal Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. The Title IV acid rain provisions of the Clean Air Act, for example, required significant reductions in sulfur dioxide and nitrogen oxide emissions. Title IV compliance, effective in 2000, and associated construction expenditures totaled approximately $88 million. Some of these expenditures also assisted the Company in complying with nitrogen oxide emission reduction requirements under Title I of the Clean Air Act, which were designed to address one-hour ozone nonattainment problems in Birmingham, Alabama. In December 2000, the Alabama Department of Environmental Management (ADEM) adopted revisions to the State Implementation Plan (SIP) for meeting the one-hour ozone standard. These revisions required additional nitrogen oxide emission reductions from May through September of each year at plants in and/or near those nonattainment areas. Two plants in the Birmingham area are currently subject to those requirements, the most recent of which went into effect in 2003. Construction expenditures for compliance with the nitrogen oxide emission reduction requirements are estimated to be approximately $249 million.
To help ozone nonattainment areas attain the one-hour ozone standard, the EPA issued regional nitrogen oxide reduction rules in 1998. Those rules required 21 states, including Alabama, to reduce and cap nitrogen oxide emissions from power plants and other large industrial sources. Affected sources, including five of the Company's coal-fired plants, must comply with the reduction requirements by May 31, 2004. Additional construction expenditures for compliance with these rules are currently estimated at approximately $361 million, of which $317 million remains to be spent.
In July 1997, the EPA revised the national ambient air quality standards for ozone and particulate matter. These revisions made the standards significantly more stringent. In the subsequent litigation of these standards, the U.S. Supreme Court found the EPA's implementation program for the new eight-hour ozone standard unlawful and remanded it to the EPA for further rulemaking. During 2003, the EPA proposed implementation rules designed to address the court's concerns. The EPA plans to designate areas as attainment or nonattainment with the new eight-hour ozone standard in April 2004 and with the new fine particulate matter standard by the end of 2004. These designations will be based on air quality data for 2001 through 2003. Several areas within the Company's service area are likely to be designated nonattainment under these standards. SIPs, including new emission control regulations necessary to bring those areas into attainment, could be required as early as 2007. These SIPs could require reductions in sulfur dioxide emissions and could require further reductions in nitrogen oxide emissions from power plants. If so, reductions could be required sometime after 2007. The impact of any new standards will depend on the development and implementation of applicable regulations and cannot be determined at this time.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2003 Annual Report
In January 2004, the EPA issued a proposed Interstate Air Quality Rule to address interstate transport of ozone and fine particles. This proposed rule would require additional year-round sulfur dioxide and nitrogen oxide emission reductions from power plants in the eastern United States in two phases - in 2010 and 2015. The EPA currently plans to finalize this rule by 2005. If finalized, the rule could modify or supplant other SIP requirements for attainment of the fine particulate matter standard and the eight-hour ozone standard. The impact of this rule on the Company will depend upon the specific requirements of the final rule and cannot be determined at this time.
Further reductions in sulfur dioxide and nitrogen oxides could also be required under the EPA's Regional Haze rules. The Regional Haze rules require states to establish Best Available Retrofit Technology (BART) standards for certain sources that contribute to regional haze. The Company has a number of plants that could be subject to these rules. The EPA's Regional Haze program calls for states to submit SIPs in 2007. The SIPs must contain emission reduction strategies for implementing BART and achieving progress toward the Clean Air Act's visibility improvement goal. In 2002, however, the U.S. Court of Appeals for the District of Columbia Circuit vacated and remanded the BART provisions of the federal Regional Haze rules to the EPA for further rulemaking. The EPA has entered into an agreement that requires proposed revised rules in April 2004 and final rules in 2005. Because new BART rules have not been developed and state visibility assessments for progress are only beginning, it is not possible to determine the effect of these rules on the Company at this time.
The EPA's Compliance Assurance Monitoring (CAM) regulations under Title V of the Clean Air Act require that monitoring be performed to ensure compliance with emissions limitations on an ongoing basis. In 2004 and 2005, a number of the Company's plants will likely become subject to CAM requirements for at least one pollutant, in most cases particulate matter. The Company is in the process of developing CAM plans. Because the plans are still under development, the Company cannot determine the costs associated with implementation of the CAM regulations. Actual ongoing monitoring costs are expensed as incurred and are not material for any year presented.
In January 2004, the EPA issued proposed rules regulating mercury emissions from electric utility boilers. The proposal solicits comments on two possible approaches for the new regulations - a Maximum Achievable Control Technology approach and a cap-and-trade approach. Either approach would require significant reductions in mercury emissions from Company facilities. The regulations are scheduled to be finalized by the end of 2004, and compliance could be required as early as 2007. Because the regulations have not been finalized, the impact on the Company cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent emissions limitations on power plants have been proposed by Congress. Three of these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2003, and the Clean Air Planning Act of 2003, propose to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills also propose to limit emissions of carbon dioxide. The cost impacts of such legislation would depend upon the specific requirements enacted and cannot be determined at this time.
Domestic efforts to limit greenhouse gas emissions, have been spurred by international discussions surrounding the Framework Convention on Climate Change and, specifically, the Kyoto Protocol, which proposes international constraints on the emissions of greenhouse gases. The Bush Administration does not support U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation and has instead announced a new voluntary climate initiative, known as Climate VISION, which seeks an 18 percent reduction by 2012 in the rate of greenhouse gas emissions relative to the dollar value of the U.S. economy. The Company is involved in a voluntary electric utility industry sector climate change initiative in partnership with the government. The electric utility sector has pledged to reduce its greenhouse gas intensity 3 percent to 5 percent over the next decade and is in the process of developing a memorandum of understanding with the Department of Energy (DOE) to cover this voluntary program.
The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and will recognize in its financial statements costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any new year presented. The Company may be liable for some
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2003 Annual Report
or all required cleanup costs for additional sites that may require environmental remediation. The Company has not incurred any significant cleanup costs to date.
Under the Clean Water Act, the EPA has been developing new rules aimed at reducing impingement and entrainment of fish and fish larvae at power plants' cooling water intake structures. On February 16, 2004, the EPA finalized these rules. These rules will require biological studies and, perhaps, retrofits to some intake structures at existing power plants. The impact of these new rules will depend on the results of studies and analyses performed as part of the rules' implementation.
In addition, under the Clean Water Act, the EPA and the ADEM are developing total maximum daily loads (TMDLs) for certain impaired waters. Establishment of maximum loads by the EPA or the ADEM may result in lowering permit limits for various pollutants and a requirement to take additional measures to control non-point source pollution (e.g., storm water runoff) at facilities that discharge into waters for which TMDLs are established. Because the effect on the Company will depend on the actual TMDLs and permit limitations established by the implementing agency, it is not possible to determine the effect on the Company at this time.
Several major pieces of environmental legislation are periodically considered for reauthorization or amendment by Congress. These 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 possible additional federal or state legislation or regulations related to global climate change, electromagnetic fields, or other environmental and health concerns could also significantly affect the Company. The impact of any new legislation, changes to existing legislation, or environmental regulations could affect many areas of the Company's operations. The full impact of any such changes cannot, however, be determined at this time.
FERC Matters
Transmission
In December 1999, the Federal Energy Regulatory Commission (FERC) issued its final rule (Order 2000) on Regional Transmission Organizations (RTOs). Order 2000 encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Through Southern Company, the Company worked with a number of utilities in the Southeast to develop a for-profit RTO known as SeTrans. In 2002, the sponsors of SeTrans established a Stakeholder Advisory Committee to provide input into the development of the RTO from other sectors of the electric industry, as well as consumers. During the development of SeTrans, state regulatory authorities expressed concern over certain aspects of the FERC's policies regarding RTOs. In December 2003, the SeTrans sponsors announced that they would suspend work on SeTrans because the regulated utility participants, including Southern Company's retail operating companies, had determined that it was highly unlikely to obtain support of both federal and state regulatory authorities. Any impact of the FERC's rule on the Company will depend on the regulatory reaction to the suspension of SeTrans and future developments, which cannot now be determined.
In July 2002, the FERC issued a notice of proposed rulemaking regarding open access transmission service and standard electricity market design. The proposal, if adopted, would among other things: (1) require transmission assets of jurisdictional utilities to be operated by an independent entity; (2) establish a standard market design; (3) establish a single type of transmission service that applies to all customers; (4) assert jurisdiction over the transmission component of bundled retail service; (5) establish a generation reserve margin; (6) establish bid caps for day ahead and spot energy markets; and (7) revise the FERC policy on the pricing of transmission expansions. Comments on the proposal were submitted by many interested parties, including Southern Company and the Company, and the FERC has indicated that it has revised certain aspects of the proposal in response to public comments. Proposed energy legislation would prohibit the FERC from issuing the final rule before October 31, 2006, and from making any final rule effective before December 31, 2006. That legislation has been approved by the House of Representatives but remains pending before the Senate. Passage of the legislation now appears in doubt. It is uncertain whether in the absence of legislation the FERC will move forward
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2003 Annual Report
with any part or all of the proposed rule. Any impact of this proposal on the Company will depend on the form in which the final rule may be ultimately adopted. However, the Company's financial statements could be adversely affected by changes in the transmission regulatory structure in its regional power market.
Hydro Relicensing
In 2002, the Company initiated the relicensing process for the Company's seven hydroelectric projects on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin) and the Smith and Bankhead Projects on the Warrior River. The FERC licenses for all of these nine projects expire in 2007. Upon or after the expiration of each license, the United States Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee. The FERC may grant relicenses subject to certain requirements that could result in additional costs to the Company.
Market-Based Rate Authority
The Company has obtained FERC approval to sell power to nonaffiliates at market-based prices under specific contracts. Through SCS, as agent, the Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities' applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company's retail operating companies, and found them to be "pivotal suppliers" in their service areas and ordered the implementation of several mitigation measures. SCS, on behalf of the retail operating companies, sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. SCS, on behalf of the retail operating companies, submitted comments to the FERC in 2002 regarding these issues. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. The Company anticipates that the FERC will address the requests for rehearing in the near future. Regardless of the outcome of the SMA proposal, the FERC retains the ability to modify or withdraw the authorization for any seller to sell at market-based rates, if it determines that the underlying conditions for having such authority are no longer applicable. The final outcome of this matter will depend on the form in which the SMA test and mitigation measures rules may be ultimately adopted and cannot be determined at this time.
Other Matters
In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash pension income, before tax, of approximately $52 million, $56 million, and $57 million in 2003, 2002, and 2001, respectively. Future pension income is dependent on several factors including trust earnings and changes to the plan. The decline in pension income is expected to continue and become an expense as early as 2011. Postretirement benefit costs for the Company were $23 million, $23 million, and $21 million in 2003, 2002, and 2001, respectively, and are expected to continue to trend upward. A portion of pension income and postretirement benefit costs is capitalized based on construction-related labor charges. Pension income or expense 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.
Prices for electricity provided by the Company to retail customers are set by the Alabama PSC under cost-based regulatory principles. Rates for the Company can be adjusted periodically within certain limitations based on earned retail rate of return compared with an allowed return range. Increases in retail rates of 2 percent were effective in both April 2002 and October 2001 in accordance with the Rate Stabilization Equalization plan.
The rates also provide for adjustments to recognize the placing of new generating facilities into retail service and the recovery of retail costs associated with certificated purchased power agreements (PPAs) under Rate CNP (Certificated New Plant). Effective July 2001, the Company's retail rates were adjusted by 0.6 percent under Rate CNP to recover costs for Plant Barry Unit 7, which was placed into commercial operation on May 1, 2001. Effective July 2003, the Company's retail rates were adjusted by approximately 2.6% under Rate CNP as a result of two new certificated PPAs that began in June 2003. See Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for additional information.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2003 Annual Report
On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act). The Medicare Act introduces a prescription drug benefit for Medicare-eligible retirees starting in 2006, as well as a federal subsidy to plan sponsors like the Company that provide prescription drug benefits. In accordance with FASB Staff Position No. 106-1, the Company has elected to defer recognizing the effects of the Medicare Act for its postretirement plans under FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other than Pension until authoritative guidance on accounting for the federal subsidy is issued or until a significant event occurs that would require remeasurement of the plans' assets and obligations. The Company anticipates that the benefits it pays after 2006 will be lower as a result of the Medicare Act; however, the retiree medical obligations and costs reported in Note 2 to the financial statements do not reflect these changes. The final accounting guidance could require changes to previously reported information.
Nuclear security legislation was recently introduced and considered in Congress both as a free-standing bill in the Senate and as a part of comprehensive energy legislation in a House-Senate Conference Report. Neither of the proposals has been enacted. The Nuclear Regulatory Commission (NRC) also ordered additional security measures for licensees in 2003. The Company is in the process of implementation and must be in full compliance with these orders by October 29, 2004. The requirements of the latest orders will have an impact on the Company's Plant Farley and will result in increased operation and maintenance expenses as well as additional capital expenditures. The precise impact of the new requirements will depend upon the details of the implementation of the new requirements, which have not been finalized.
The Company filed an application with the NRC in September 2003 to extend the operating license for Plant Farley for an additional 20 years. If approved by the NRC, the Company's depreciation and amortization expense could be reduced pending approval by the Alabama PSC.
The Company is involved in various matters being litigated and regulatory matters that could affect future earnings. 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 discussed the development and selection of the critical accounting policies and estimates described below with the Controls and Compliance Committee of the Company's Board of Directors and the Audit Committee of Southern Company's Board of Directors.
Electric Utility Regulation
The Company is subject to retail regulation by the Alabama PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of Statement No. 71 has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and post-retirement 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 under "Regulatory Assets and Liabilities," significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2003 Annual Report
assets and liabilities based on applicable regulatory guidelines. However, adverse legislation and 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" 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:
o 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. o Changes in existing income tax regulations or changes in Internal Revenue Service interpretations of existing regulations. o Identification of sites that require environmental remediation or the filing of other complaints in which the Company may be asserted to be a potentially responsible party. o Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant. o Resolution or progression of existing matters through the legislative process, the court systems, or the EPA.
New Accounting Standards
Prior to January 2003, the Company accrued for the ultimate cost of retiring most long-lived assets over the life of the related asset through depreciation expense. FASB Statement No. 143, Accounting for Asset Retirement Obligations established new accounting and reporting standards for legal obligations associated with the ultimate cost of retiring long-lived assets. The present value of the ultimate costs of an asset's future retirement is recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Additionally, non-regulated companies are no longer permitted to continue accruing future retirement costs for long-lived assets that they do not have a legal obligation to retire. For more information regarding the impact of adopting this standard effective January 1, 2003, see Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal."
FASB Statement No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, which further amends and clarifies the accounting and reporting for derivative instruments, became effective generally for financial instruments entered into or modified after June 30, 2003. Current interpretations of Statement No. 149 indicate that certain electricity forward transactions subject to unplanned netting -- including those typically referred to as "book outs" -- may only qualify as cash flow hedges if an entity can demonstrate that physical delivery or receipt of power occurred. The Company's forward electricity contracts continue to be exempt from fair value accounting requirements or to qualify as cash flow hedges, with the related gains and losses deferred in other comprehensive income. The implementation of Statement No. 149 did not have a material effect on the Company's financial statements.
In July 2003, the Emerging Issues Task Force (EITF) of FASB issued EITF No. 03-11, which became effective on October 1, 2003. The standard addresses the reporting of realized gains and losses on derivative instruments and is being interpreted to require book outs to be recorded on a net basis in operating revenues. Adoption of this standard did not have a material impact on the Company's financial statements.
FASB Interpretation No. 46, Consolidation of Variable Interest Entities, which was originally issued in January 2003, requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. In December 2003, the FASB revised Interpretation No. 46 and deferred the effective date until March 31, 2004 for interests held in variable interest entities other than special purpose entities.
Current analysis indicates that the trusts established by the Company to issue preferred securities are variable interest entities under Interpretation No. 46, and that the Company is not the primary beneficiary of these trusts. If
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2003 Annual Report
this conclusion is finalized, effective March 31, 2004, the trust assets and liabilities -- including the preferred securities issued by the trusts -- will be deconsolidated. The investments in the trusts and the loans from the trusts to the Company will be reflected as equity method investments and as long-term notes payable to affiliates, respectively, on the Balance Sheets. Based on December 31, 2003 values, this treatment would result in an increase of approximately $9 million to both total assets and total liabilities. See Note 6 to the financial statements under "Mandatorily Redeemable Preferred Securities" for additional information.
In May 2003, the FASB issued Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity, which requires classification of certain financial instruments within its scope, including shares that are mandatorily redeemable, as liabilities. Statement No. 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise on July 1, 2003. In accordance with Statement No. 150, mandatorily redeemable preferred securities are reflected in the Balance Sheets as liabilities. The adoption of Statement No. 150 had no impact on the Statements of Income and Cash Flows.
FINANCIAL CONDITION AND LIQUIDITY - ---------------------------------
Overview
Over the last several years, the Company's financial condition has remained stable with emphasis on cost control measures combined with significantly lower cost of capital, achieved through the refinancing and/or redemption of higher-cost long-term debt and preferred stock. The Company operated at high levels of reliability while achieving industry-leading customer satisfaction levels and continuing to have retail prices below the national average.
The Company had gross property additions of $649 million in 2003. The majority of funds needed for gross property additions for the last several years have been provided from operating activities. The Statements of Cash Flows provide additional details.
The Company's ratio of common equity to total capitalization -- including short-term debt -- was 43.3 percent in 2003, 42.6 percent in 2002, and 42.8 percent in 2001. See Note 6 to the financial statements for additional information.
Sources of Capital
The Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows. However, the type and timing of any financings -- if needed -- will depend on market conditions and regulatory approval. In recent years, financings primarily have utilized unsecured debt and preferred securities.
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. In accordance with the Public Utility Holding Company Act, most loans between affiliated companies must be approved in advance by the Securities and Exchange Commission (SEC).
The Company's current liabilities exceed current assets because of securities due within one year. The Company intends to refinance debt that comes due during 2004.
To meet short-term cash needs and contingencies, the Company has various internal and external sources of liquidity. At the beginning of 2004, the Company had approximately $43 million of cash and cash equivalents and $865 million of unused credit arrangements with banks, as shown in the following table. 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. Cash flows from operating activities were $1,118 million in 2003, $973 million in 2002, and $843 million in 2001.
At the beginning of 2004, bank credit arrangements are as follows:
Expires ---------------------------------- Total Unused 2004 & Beyond - ------------------------------------------------------------------ (in millions) $865 $865 $865 - - -----------------------------------------------------------------
Approximately $450 million of the credit facilities expiring in 2004 allow for the execution of term loans for an additional two-year period and $245 million allow for the execution for a one-year period. See Note 6 to the
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2003 Annual Report
financial statements under "Bank Credit Arrangements" for additional information.
The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other Southern Company retail operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other operating company. The obligations of each company under these arrangements are several; there is no cross affiliate credit support. At December 31, 2003, the Company had no commercial paper outstanding.
Financing Activities
In 2003, the Company's financing costs decreased due to lower interest rates despite the issuance of an increased amount of senior securities during the year. New issues during 2001 through 2003 totaled $3.3 billion and retirement or repayment of higher-cost securities totaled $2.8 billion.
Composite financing rates for long-term debt, preferred stock, and preferred securities for the years 2001 through 2003, as of year-end, were as follows:
2003 2002 2001 - ---------------------------------------------------------------- Long-term debt interest rate 4.42% 5.05% 5.72% Preferred securities distribution rate 5.25 5.25 6.96 Preferred stock dividend rate 5.10 5.17 4.79 - ----------------------------------------------------------------
Subsequent to December 31, 2003, the Company has entered into interest rate hedging transactions related to the anticipated refinancing of $470 million of securities due within one year. Also, an additional $300 million of securities have been issued for other general corporate purposes including repayment of outstanding short-term indebtedness and the funding of the Company's continuous construction program.
Credit Rating Risk
The Company does not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are contracts that could require collateral -- but not accelerated payment -- in the event of a credit rating change to below investment grade. These contracts are primarily for physical electricity purchases and sales, fixed-price physical gas purchases, and agreements covering interest rate swaps. At December 31, 2003, the maximum potential collateral requirements under the electricity purchase and sale contracts were approximately $26.7 million. Generally, collateral may be provided for by a Company guaranty, a letter of credit, or cash. At December 31, 2003, there were no material collateral requirements for the gas purchase contracts or other financial instrument agreements.
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 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.
To mitigate exposure to interest rates, the Company has entered into interest rate swaps that have been designated as hedges. The weighted average interest rate on outstanding variable long-term debt, that has not been hedged at December 31, 2003 was 1.38 percent. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $0.5 million at December 31, 2003. The Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term. For further information, see Notes 1 and 6 to the financial statements under "Financial Instruments."
To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market, and, to a lesser extent, into similar contracts for gas purchases.
In addition, in October 2001, the Alabama PSC approved a revision to the Company's Rate ECR (Energy Cost Recovery) allowing the recovery of specific costs associated with the sales of natural gas that become necessary due to
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2003 Annual Report
operating considerations at its electric generating facilities. This revision also includes the cost of financial instruments used for hedging market price risk up to 75 percent of the budgeted annual amount of natural gas purchases. The Company may not engage in natural gas hedging activities that extend beyond a rolling 42-month window. Also, the premiums paid for natural gas financial options may not exceed 5 percent of the Company's natural gas budget for that year.
At December 31, 2003, 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 derivative energy contracts and year-end valuations were as follows:
Changes in Fair Value - --------------------------------------------------------------- 2003 2002 - --------------------------------------------------------------- (in thousands) Contracts beginning of year $ 21,402 $ 214 Contracts realized or settled (38,809) (21,088) New contracts at inception - - Changes in valuation techniques - - Current period changes 23,820 42,276 - -------------------------------------------------------------- Contracts end of year $ 6,413 $ 21,402 ==============================================================
Source of 2003 Year-End Valuation Prices ---------------------------------- Maturity Total ------------------------- Fair Value 2004 2005-2006 - -------------------------------------------------------------- (in thousands) - -------------------------------------------------------------- Actively quoted $6,413 $7,803 $ (1,390) External sources - - - Models and other methods - - - - -------------------------------------------------------------- Contracts end of Year $6,413 $7,803 $ (1,390) ==============================================================
Unrealized gains and losses from mark to market adjustments on derivative contracts related to the Company's fuel hedging programs are recorded as regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are recovered through the Company's fuel cost recovery clause. Gains and losses on derivative contracts that are not designated as hedges are recognized in the income statement as incurred. At December 31, 2003, the fair value of derivative energy contracts was reflected in the financial statements as follows: Amounts --------------------------------------------------------- (in thousands) Regulatory liabilities, net $6,402 Net income 11 ---------------------------------------------------------- Total fair value $6,413 ==========================================================
Unrealized pre-tax gains (losses) on energy contracts of $(0.1) million, $(2.0) million, and $2.0 million were recognized in income in 2003, 2002, and 2001, respectively. 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 $791 million for 2004, $863 million for 2005, and $884 million for 2006. Over the next three years, the Company estimates spending $713 million on environmental related additions (including $358 million on Selective Catalytic Reduction facilities), $267 million on Plant Farley (including $155 million for nuclear fuel, $29 million on cooling towers and $26 million on replacing reactor vessel heads), $701 million on distribution facilities, and $402 million on transmission additions. See Note 7 to the financial statements under "Construction Program" for additional details.
Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
In addition to the funds required for the Company's construction program, approximately $1.5 billion will be required by the end of 2006 for maturities of long-term debt. The Company plans to continue, when economically feasible, to retire higher cost debt, preferred securities, and preferred stock and replace these obligations with lower-cost capital if market conditions permit.
As a result of requirements by the NRC, the Company has established external trust funds for the purpose of funding nuclear decommissioning costs. Annual provisions for nuclear decommissioning are based on an annuity method as
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2003 Annual Report
approved by the Alabama PSC. The amount expensed in 2003 was $18 million. For additional information, see Note 1 to the financial statements under "Nuclear Decommissioning." Additionally, as discussed in Note 1 to the financial statements under "Revenues and Fuel Costs," in 1993, the DOE implemented a special assessment over a 15-year period on utilities with nuclear plants to be used for the decontamination and decommissioning of its nuclear fuel enrichment facilities.
In 1994, the Company 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 and may require capital from other sources. For additional information, see Note 2 to the financial statements under "Postretirement Benefits."
The capital requirements, lease obligations, purchase commitments, and trust requirements - discussed above and in the financial statements - are summarized 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) Alabama Power Company 2003 Annual Report
Cautionary Statement Regarding Forward-Looking Information
The Company's 2003 Annual Report includes forward-looking statements in addition to historical information. Forward-looking information includes, among other things, statements concerning the Company's estimated construction and other expenditures, and the Company's projections for energy sales and its goals for future generating capacity and earnings growth. 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 comparable terminology. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
o 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 and also changes in environmental, tax, and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations; o current and future litigation, regulatory investigations, proceedings or inquiries, including the pending EPA civil action against the Company; o the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates; o the impact of fluctuations in commodity prices, interest rates, and customer demand; o available sources and costs of fuels; o ability to control costs; o investment performance of the Company's employee benefit plans; o advances in technology; o state and federal rate regulations and pending and future rate cases and negotiations; o effects of and changes in political, legal, and economic conditions and developments in the United States, including the current soft economy; o internal restructuring or other restructuring options that may be pursued; o potential business strategies, including acquisitions or dispositions of assets, which cannot be assured to be completed or beneficial to the Company; o the ability of counterparties of the Company to make payments as and when due; o the ability to obtain new short- and long-term contracts with neighboring utilities; o the direct or indirect effects on the Company's business resulting from the terrorist incidents on September 11, 2001, or any similar incidents or responses to such incidents; o financial market conditions and the results of financing efforts, including the Company's credit ratings; o the ability of the Company to obtain additional generating capacity at competitive prices; o weather and other natural phenomena; o the direct or indirect effects on the Company's business resulting from the August 2003 power outage in the Northeast, or any similar incidents; o the effect of accounting pronouncements issued periodically by standard-setting bodies; and o other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed from time to time by the Company with the SEC.
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NOTES TO FINANCIAL STATEMENTS Alabama Power Company 2003 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Alabama Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of five retail operating companies, Southern Power Company (Southern Power), Southern Company Services (SCS), Southern Communications Services (Southern LINC), Southern Company Gas (Southern Company GAS), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The retail operating companies -- the Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company -- provide electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast. Southern Power constructs, owns, and manages Southern Company's competitive generation assets and sells electricity at market-based rates in the wholesale market. Contracts among the retail operating companies and Southern Power -- related to jointly-owned generating facilities, interconnecting transmission lines, or the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission (SEC). SCS -- the system service company -- provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern Company GAS is a competitive retail natural gas marketer serving customers in Georgia. Southern Holdings is an intermediate holding subsidiary for Southern Company's investments in synthetic fuels and leveraged leases and an energy services business. Southern Nuclear operates and provides services to Southern Company's nuclear power plants, including the Company's Plant Farley.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The Company is also subject to regulation by the FERC and the Alabama Public Service Commission (Alabama 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.
Certain prior years' data presented in the financial statements have been reclassified to conform with current year presentation.
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 $218 million, $218 million, and $183 million during 2003, 2002, and 2001, respectively. Cost allocation methodologies used by SCS are approved by the SEC and management believes they are reasonable.
The Company has an agreement with Southern Nuclear to operate Plant Farley and provide 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 $153 million, $154 million, and $160 million during 2003, 2002, and 2001, respectively.
The Company has an agreement with Mississippi Power under which Mississippi Power owns a portion of Plant Greene County. The Company operates Plant Greene County, and Mississippi Power reimburses the Company for its proportionate share of expenses which were $6.7 million in 2003, $6.4 million in 2002, and $5.5 million in 2001. See Note 4 for additional information.
Southern Company holds a 30 percent ownership interest in Alabama Fuel Products, LLC (AFP), which produces synthetic fuel. The Company has an agreement with an indirect subsidiary of Southern Company that provides services for AFP. Under this agreement, the Company provides certain accounting functions, including processing and paying fuel transportation invoices, and the Company is
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NOTES (continued) Alabama Power Company 2003 Annual Report
reimbursed for its expenses. Amounts billed under this agreement totaled approximately $27.5 million and $34.5 million in 2003 and 2002, respectively. In addition, the Company purchases synthetic fuel from AFP for use at several of the Company's plants. Fuel purchases for 2003 and 2002 totaled $209.2 million and $211.0 million, respectively.
In 2001, the Company had under construction a 1,230 megawatt combined cycle facility in Autaugaville, Alabama (Plant Harris). In June 2001, the Company sold this project to Southern Power. Upon the plant becoming operational in June 2003, the Company entered into an agreement with Southern Power to operate and maintain Plant Harris at cost and provide fuel at cost. In 2003, the Company billed Southern Power $0.8 million for operation and maintenance. Purchased power costs from Plant Harris in 2003 totaled $75.6 million. Additionally, the Company recorded $8.3 million of prepaid capacity expenses included in Other Deferred Charges and Other Assets on the Balance Sheets at December 31, 2003. See Note 3 under "Retail Rate Adjustment Procedures" and Note 7 under "Purchased Power Commitments" for additional information.
Also, see Note 4 for information regarding the Company's ownership in and purchased power agreement with Southern Electric Generating Company (SEGCO).
The retail operating companies, including the Company, Southern Power, and Southern Company GAS, 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.
Revenues and Fuel Costs
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 are accrued at the end of each fiscal period. Fuel costs are expensed as the fuel is used. 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 recoverable fuel costs and amounts actually recovered in current regulated rates.
The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts continued to average less than 1 percent of revenues.
Fuel expense includes the amortization of the cost of nuclear fuel and a charge based on nuclear generation for the permanent disposal of spent nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted to $64 million in 2003, $63 million in 2002, and $58 million in 2001. The Company has a contract with the U.S. Department of Energy (DOE) that provides for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent fuel in January 1998 as required by the contract, and the Company is pursuing legal remedies against the government for breach of contract. Sufficient pool storage capacity for spent fuel is available at Plant Farley to maintain full-core discharge capability until the refueling outage scheduled in 2006 for Plant Farley Unit 1 and the refueling outage scheduled in 2008 for Plant Farley Unit 2. Procurement of on-site dry spent fuel storage capacity at Plant Farley is in progress and scheduled for operation in 2005. See Note 7 under "Construction Program" for additional information.
Also, the Energy Policy Act of 1992 required the establishment of a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants. This assessment is being paid over a 15-year period, which began in 1993. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. The Company estimates its remaining liability under this law to be approximately $13 million at December 31, 2003.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with
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NOTES (continued) Alabama Power Company 2003 Annual Report
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:
2003 2002 Note --------------- ---- (in millions) Deferred income tax charges $ 321 $ 327 (a) Loss on reacquired debt 111 104 (b) DOE assessments 13 17 (c) Vacation pay 36 34 (d) Rate CNP under recovery 17 - (e) Other assets 13 17 (e) Asset retirement obligations (127) - (a) Other cost of removal obligations (574) (885) (a) Deferred income tax credits (162) (177) (a) Natural disaster reserve (13) (12) (e) Nuclear outage (14) (10) (e) Deferred purchased power (15) - (e) Other liabilities (5) (2) (e) Fuel-hedging liabilities (6) (21) (f) Mine reclamation & remediation (33) (35) (g) - ------------------------------------------------------ Total $(438) $(643) ====================================================== 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 40 years. (c) Assessments for the decontamination and decommissioning of the DOE nuclear fuel enrichment facilities are recorded annually from 1993 through 2008. (d) Recorded as earned by employees and recovered as paid, generally within one year. (e) Recorded and recovered or amortized as approved by the Alabama PSC. (f) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clauses. (g) Recovered from customers to settle future costs.
In the event that a portion of the Company's operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are reflected in rates.
Depreciation and Amortization
Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.1 percent in 2003 and 3.2 percent in each of 2002 and 2001. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost -- together with the cost of removal, less salvage -- is charged to accumulated depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.
Asset Retirement Obligations and Other Costs of Removal
In accordance with regulatory requirements, prior to January 2003, the Company followed the industry practice of accruing for the ultimate costs of retiring most long-lived assets over the life of the related asset as part of the annual depreciation expense provision. In accordance with SEC requirements, such amounts are reflected on the Balance Sheet as regulatory liabilities. Effective January 1, 2003, the Company adopted FASB Statement No. 143, Accounting for Asset Retirement Obligations. Statement No. 143 establishes new accounting and reporting standards for legal obligations associated with the ultimate costs of retiring long-lived assets. The present value of the ultimate costs of an asset's future retirement must be recorded in the period in which the liability is incurred. The costs must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Additionally, Statement No. 143 does not permit the continued accrual of future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. However, the Company has received guidance regarding accounting for the financial statement impacts of Statement No. 143 from the Alabama PSC and will continue to recognize the accumulated removal costs for other obligations as a regulatory liability. Therefore, the Company had no cumulative effect to net income resulting from the adoption of Statement No. 143.
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, 2003 was $385 million. In addition, the Company has retirement
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obligations related to various landfill sites and underground storage tanks. The Company has also 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, a liability for the removal of these assets will not be recorded because no reasonable estimate can be made regarding the timing of any related retirements. The Company will continue to recognize in the income statement allowed removal costs in accordance with its regulatory treatment. Any difference between costs recognized under Statement No. 143 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. The Company also revised the estimated cost to retire Plant Farley as a result of a new site-specific decommissioning study. The effect of the revision is an increase of $35 million included in asset retirement obligations, with a corresponding increase in property, plant, and equipment. 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: ---------------- (in millions) Balance beginning of year $ - Liabilities incurred 301 Liabilities settled - Accretion 23 Cash flow revisions 35 - --------------------------------------------------------------- Balance end of year $ 359 ===============================================================
If Statement No. 143 had been adopted on January 1, 2002, the pro-forma asset retirement obligations would have been $281 million.
Nuclear Decommissioning
The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial nuclear power reactors to establish a plan for providing with reasonable assurance funds for decommissioning. The Company has established external trust funds to comply with the NRC's regulations. The funds set aside for decommissioning 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). Funds are invested in a tax efficient manner in a diversified mix of equity and fixed income securities. Equity securities typically range from 50 to 75 percent of the funds and fixed income securities from 25 to 50 percent. 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 the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC 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 the facility as of the site study year. The estimated costs of decommissioning, based on the most current study as of December 31, 2003, for Plant Farley were as follows:
Site study year 2003 Decommissioning periods: Beginning year 2017 Completion year 2046 ------------------------------------------------------------- (in millions) Site study costs: Radiated structures $892 Non-radiated structures 63 ------------------------------------------------------------- Total $955 =============================================================
Significant assumptions: Inflation rate 4.5% Trust earning rate 7.0 -------------------------------------------------------------
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 estimates.
Annual provisions for nuclear decommissioning are based on an annuity method as approved by the Alabama PSC. The amount expensed in 2003 and fund balances were as follows:
(in millions) Amount expensed in 2003 $ 18 ------------------------------------------------------------- Accumulated provisions: External trust funds, at fair value $ 385 Internal reserves 31 ------------------------------------------------------------- Total $ 416 =============================================================
All of the Company's decommissioning costs for ratemaking are based on the site study. The Company expects the Alabama PSC to periodically review and
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adjust, if necessary, the amounts collected in rates for the anticipated cost of decommissioning.
The Company filed an application with the NRC in September 2003 to extend the operating license for Plant Farley for an additional 20 years.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized
In accordance with regulatory treatment, the Company records AFUDC. AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. Interest related to the construction of new facilities not included in the Company's regulated rates is capitalized in accordance with standard interest capitalization requirements. All current construction costs should be included in retail rates. The composite rate used to determine the amount of AFUDC was 9.0 percent in 2003, 8.2 percent in 2002, and 7.7 percent in 2001. AFUDC and interest capitalized, net of income tax, as a percent of net income after dividends on preferred stock was 3.5 percent in 2003 and 3.3 percent in each of 2002 and 2001.
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 cost of replacements of property -- exclusive of minor items of property -- is capitalized. The cost of maintenance, repairs and replacement of minor items of property is charged to maintenance expense as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific Alabama PSC orders. The Company accrues estimated refueling costs in advance of the unit's next refueling outage. The refueling cycle is 18 months for each unit. During 2003, the Company accrued $28.5 million to the nuclear refueling outage reserve and at December 31, 2003 the reserve balance was $14.0 million.
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 either by the amount of the regulatory disallowance or by estimating the fair value of the assets and recording a provision for loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment provision is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
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 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.
Natural Disaster Reserve
In accordance with an Alabama PSC order, the Company has established a Natural Disaster Reserve. The Company is allowed to accrue $250 thousand per month until the maximum accumulated provision of $32 million is attained. Higher accruals to restore the reserve to its authorized level are allowed whenever the balance in the reserve declines below $22.4 million. During 2003, the Company accrued $3 million to the reserve and at December 31, 2003, the reserve balance was $12.6 million.
Stock Options
Southern Company provides non-qualified stock options to a large segment of the Company's employees ranging from line management to executives. The Company accounts for its stock-based compensation plans in accordance with Accounting Principles Board Opinion No. 25. Accordingly, no compensation expense has been
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recognized because the exercise price of all options granted equaled the fair-market value on the date of grant. When options are exercised, the Company receives a capital contribution from Southern Company equivalent to the related income tax benefit.
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 or regulatory assets or liabilities as appropriate 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 other financial instruments for which the carrying amount did not equal fair value at December 31 were as follows:
Carrying Fair Amount Value ------------------------- (in millions)
Long-term debt: At December 31, 2003 $3,903 $3,958 At December 31, 2002 3,991 4,065 Preferred Securities: At December 31, 2003 300 305 At December 31, 2002 300 303 --------------------------------------------------------------
The fair value for long-term debt and preferred securities was 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 changes in additional minimum pension liabilities, less income taxes and reclassifications for amounts included in net income.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with Employee Retirement Income Security Act (ERISA) requirements. The Company also provides certain non-qualified benefit plans for a selected group of management and highly-compensated employees. Benefits under these non-qualified plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees. The Company funds trusts to the extent required by the Alabama PSC. For the year ended December 31, 2004, postretirement benefit contributions are expected to total approximately $4.2 million.
The measurement date for plan assets and obligations is September 30 for each year. In 2002, the Company adopted several plan changes that had the effect of increasing benefits to both current and future retirees.
Pension Plans
The accumulated benefit obligation for the pension plans was $1.20 billion in 2003 and $1.09 billion in 2002. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:
Projected Benefit Obligations --------------------------- 2003 2002 - ------------------------------------------------------------- (in millions) Balance at beginning of year $1,088 $1,011 Service cost 27 26 Interest cost 68 74 Benefits paid (61) (61) Plan amendments 3 22 Actuarial (gain) loss 75 16 - ------------------------------------------------------------- Balance at end of year $1,200 $1,088 =============================================================
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Plan Assets --------------------------- 2003 2002 - ------------------------------------------------------------- (in millions) Balance at beginning of year $1,419 $1,584 Actual return on plan assets 226 (106) Benefits paid (62) (59) - ------------------------------------------------------------- Balance at end of year $1,583 $1,419 =============================================================
Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the IRS revenue code. The Company's investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.
Plan Assets ------------------------------ Target 2003 2002 - ------------------------------------------------------------- Domestic equity 37% 37% 35% International equity 20 20 18 Global fixed income 26 24 25 Real estate 10 11 12 Private equity 7 8 10 - ------------------------------------------------------------- Total 100% 100% 100% =============================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
2003 2002 - ------------------------------------------------------------- (in millions) Funded status $383 $331 Unrecognized transition amount (5) (10) Unrecognized prior service cost 87 93 Unrecognized net (gain) loss (37) (40) - -------------------------------------------------------------- Prepaid pension asset, net 428 374 Portion included in benefit obligations 18 16 - ------------------------------------------------------------- Total prepaid assets recognized in the Balance Sheets $446 $390 =============================================================
In 2003 and 2002, amounts recognized in the Balance Sheets for accumulated other comprehensive income and intangible assets to record the minimum pension liability related to the non-qualified plans were $12.8 million and $6.7 million and $6.7 and $4.8 million, respectively.
Components of the pension plans' net periodic cost were as follows:
2003 2002 2001 - ------------------------------------------------------------- (in millions) Service cost $ 27 $ 26 $ 25 Interest cost 68 74 70 Expected return on plan assets (138) (138) (131) Recognized net gain (12) (20) (22) Net amortization 3 2 1 - ------------------------------------------------------------- Net pension cost (income) $ (52) $(56) $ (57) =============================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:
Accumulated Benefit Obligations --------------------------- 2003 2002 - ------------------------------------------------------------- (in millions) Balance at beginning of year $405 $348 Service cost 6 5 Interest cost 26 26 Benefits paid (20) (20) Actuarial (gain) loss 24 46 - ------------------------------------------------------------- Balance at end of year $441 $405 =============================================================
Plan Assets --------------------------- 2003 2002 - ------------------------------------------------------------- (in millions) Balance at beginning of year $158 $169 Actual return on plan assets 25 (12) Employer contributions 23 21 Benefits paid (20) (20) - ------------------------------------------------------------- Balance at end of year $186 $158 =============================================================
Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the IRS revenue code. The Company's investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.
Plan Assets ------------------------------ Target 2003 2002 - ------------------------------------------------------------- Domestic equity 46% 50% 42% International equity 13 14 9 Global fixed income 34 28 40 Real estate 4 5 5 Private equity 3 3 4 - ------------------------------------------------------------- Total 100% 100% 100% =============================================================
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The accrued postretirement costs recognized in the Balance Sheets were as follows: 2003 2002 - ------------------------------------------------------------- (in millions) Funded status $(255) $(247) Unrecognized transition obligation 37 41 Unrecognized prior service cost 73 77 Unrecognized net loss (gain) 82 66 Fourth quarter contributions 6 8 - ------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ (57) $ (55) =============================================================
Components of the postretirement plan's net periodic cost were as follows: 2003 2002 2001 - ------------------------------------------------------------- (in millions) Service cost $ 6 $ 5 $ 5 Interest cost 25 25 24 Expected return on plan assets (17) (16) (15) Net amortization 9 9 7 - ------------------------------------------------------------- Net postretirement cost $ 23 $ 23 $ 21 =============================================================
The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations and the net periodic costs for the pension and postretirement benefit plans were as follows:
2003 2002 2001 - --------------------------------------------------------------- Discount 6.00% 6.50% 7.50% Annual salary increase 3.75 4.00 5.00 Long-term return on plan assets 8.50 8.50 8.50 - ---------------------------------------------------------------
The Company determined the long-term rate of return 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 accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 8.25 percent for 2003, decreasing gradually to 5.25 percent through the year 2010, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2003 as follows:
1 Percent 1 Percent Increase Decrease - --------------------------------------------------------------- (in millions) Benefit obligation $34 $30 Service and interest costs 2 2 =================================================================
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee's base salary. Total matching contributions made to the plan were $12 million for each of the years 2003, 2002, and 2001.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements, 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 litigation against the Company cannot be predicted at this time; however, 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.
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against the Company. The complaint alleged violations of the New Source Review (NSR) provisions of the Clean Air Act and violations of related state laws with respect to coal-fired generating facilities at the Company's Plants Miller, Barry, and Gorgas. The civil action requested penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued to the Company a notice of violation relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation.
In August 2000, the U.S. District Court in Georgia granted the Company's motion to dismiss for lack of jurisdiction in Georgia. The EPA refiled its claim against the Company in the U.S. District Court for the Northern District of
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Alabama. The EPA brought similar NSR enforcement actions against several other electric utility companies across the country including Georgia Power and Savannah Electric. In each case, the EPA alleged that the utilities failed to comply with the NSR permitting requirements when performing maintenance and construction activities at coal-burning plants, which activities the utilities considered to be routine or otherwise not subject to NSR.
The action against the Company was stayed in the spring of 2001 during the appeal of a very similar NSR enforcement action against the Tennessee Valley Authority (TVA) before the U.S. Court of Appeals for the Eleventh Circuit. The TVA appeal involves many of the same legal issues raised by the actions against the Company. Because the final resolution of the TVA appeal could have a significant impact on the Company, it has been involved in that appeal. On June 24, 2003, the court of appeals issued its ruling in the TVA case. It found unconstitutional the statutory scheme set forth in the Clean Air Act that allowed the EPA to impose penalties for failing to comply with an administrative compliance order, like the one issued to TVA, without the EPA having to prove the underlying violation. Thus, the court of appeals held that the compliance order was of no legal consequence, and TVA was free to ignore it. The court did not, however, rule directly on the substantive legal issues about the proper interpretation and application of certain NSR provisions that had been raised in the TVA appeal. On September 16, 2003, the court of appeals denied the EPA's request for a rehearing of the decision. On February 13, 2004, the EPA petitioned the U.S. Supreme Court to review the decision of the court of appeals. The EPA also filed a motion to lift the stay in the action against the Company.
Since the inception of the NSR proceedings against the Company, the EPA has also been proceeding with similar NSR enforcement actions against other utilities, involving many of the same legal issues. In each case, the EPA alleged that the utilities failed to comply with the NSR permitting requirements when performing maintenance and construction activities at coal-burning plants, which activities the utilities considered to be routine or otherwise not subject to NSR. In 2003, district courts addressing these cases have issued opinions that reached conflicting conclusions.
In October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act clarifying the scope of the existing Routine Maintenance, Repair, and Replacement exclusion. On December 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit stayed the effectiveness of these revisions pending resolution of related litigation over those revisions. In January 2004, the Bush Administration announced that it would continue to enforce the existing rules.
The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome in this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
Open Access Transmission Tariff
In October 2003, the FERC approved a new Open Access Transmission Tariff for the Company of $1.73 per kilowatt-month based on an 11.25 percent return on equity. The Company had requested a rate increase effective April 2002 based on a 13 percent return on equity. In September 2002, pending FERC approval, the Company began collecting from customers based on the 13 percent rate, but recorded revenue subject to refund for amounts above the previously approved rate of $1.37 per kilowatt-month. As a result of the final settlement, a total of approximately $2.4 million was refunded to the Company's transmission customers in October 2003 and $7.6 million was recorded as revenue.
Retail Rate Adjustment Procedures
The Alabama PSC has adopted rates that provide for periodic adjustments based upon the Company's earned return on end-of-period retail common equity. Increases in retail rates of 2 percent were effective in April 2002 and in October 2001 in accordance with the Rate Stabilization Equalization Plan, amounting to an annual increase of $55 million and $58 million, respectively. In March 2002, the Alabama PSC approved a revision to the rate adjustment procedures that provides for an annual, rather than quarterly, adjustment and imposes a 3 percent limit on changes in rates in any calendar year. The return on common equity range of 13.0 percent to 14.5 percent remained unchanged.
The rates also provide for adjustments to recognize the placing of new generating facilities into retail service and the recovery of retail costs
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associated with certificated purchased power agreements (PPAs) under Rate CNP (Certificated New Plant). Effective July 2001, the Company's retail rates were adjusted by 0.6 percent ($17 million annually) under Rate CNP to recover costs for Plant Barry Unit 7, which was placed into commercial operation on May 1, 2001.
In November 2000, the Alabama PSC certificated a seven-year, 615 megawatt, PPA with Southern Power beginning in June 2003. In addition, the Alabama PSC certificated a seven-year PPA with a third party for approximately 630 megawatts; one half of the capacity became available in 2003 while the remaining half is scheduled to become available in 2004. As a result, the Company's retail rates were adjusted beginning July 2003 by approximately 2.6 percent ($79 million annually) under Rate CNP. One month after the contracted capacity delivery begins, which is scheduled for June 2004, Rate CNP will adjust retail rates by approximately 0.8 percent ($25 million annually) to recover costs associated with the scheduled 2004 PPA capacity.
In October 2001, the Alabama PSC approved a revision to the Company's Rate ECR (Energy Cost Recovery) allowing the recovery of specific costs associated with the sales of natural gas that become necessary due to operating considerations at its electric generating facilities. This revision also includes the cost of financial tools used for hedging market price risk up to 75 percent of the budgeted annual amount of natural gas purchases. The Company may not engage in natural gas hedging activities that extend beyond a rolling 42-month window. Also, the premiums paid for natural gas financial options may not exceed 5 percent of the Company's natural gas budget for that year.
The Company's ratemaking procedures will remain in effect until the Alabama PSC votes to modify or discontinue them.
FERC Matters
The Company has obtained FERC approval to sell power to nonaffiliates at market-based prices under specific contracts. Through SCS, as agent, the Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities' applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company's retail operating companies, and found them to be "pivotal suppliers" in their service areas and ordered the implementation of several mitigation measures. SCS, on behalf of the retail operating companies, sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. SCS, on behalf of the retail operating companies, submitted comments to the FERC in 2002 regarding these issues. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. The Company anticipates that the FERC will address the requests for rehearing in the near future. Regardless of the outcome of the SMA proposal, the FERC retains the ability to modify or withdraw the authorization for any seller to sell at market-based rates, if it determines that the underlying conditions for having such authority are no longer applicable. The final outcome of this matter will depend on the form in which the SMA test and mitigation measures rules may be ultimately adopted and cannot be determined at this time.
4. JOINT OWNERSHIP AGREEMENTS
The Company and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 megawatts, together with 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 $87 million in 2003, $84 million in 2002, and $80 million in 2001 and is included in "Purchased power from affiliates" in the Statements of Income.
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. Georgia Power has agreed to reimburse the Company for the pro rata portion of such obligation corresponding to its then proportionate ownership of stock of SEGCO if the Company is called upon to make such payment under its guaranty.
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At December 31, 2003, the capitalization of SEGCO consisted of $63 million of equity and $94 million of debt on which the annual interest requirement is $3.4 million. SEGCO paid dividends totaling $2.3 million in 2003, $5.8 million in 2002, and $0.7 million in 2001, of which one-half of each was paid to the Company. In addition, the Company recognizes 50 percent of SEGCO's net income.
In addition to the Company's ownership of SEGCO, the Company's percentage ownership and investment in jointly-owned generating plants at December 31, 2003 is as follows:
Total Megawatt Company Facility (Type) Capacity Ownership --------------------- ------------ ------------ Greene County 500 60.00% (1) (coal) Plant Miller Units 1 and 2 1,320 91.84% (2) (coal) ------------------------------------------------------ (1) Jointly owned with an affiliate, Mississippi Power. (2) Jointly owned with Alabama Electric Cooperative, Inc.
Company Accumulated Facility Investment Depreciation --------------------- -------------- --------------- (in millions) Greene County $110 $ 54 Plant Miller Units 1 and 2 767 355 ----------------------------------------------------------
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 the operating expenses in the Statements of Income.
5. INCOME TAXES
Southern Company files a consolidated federal income tax return. Under a joint consolidated income tax 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.
At December 31, 2003, the Company's tax-related regulatory assets and liabilities were $321 million and $162 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.
Details of the income tax provisions are as follows:
2003 2002 2001 -------------------------------- (in millions) Total provision for income taxes: Federal -- Current $111 $209 $234 Deferred 137 41 (20) - ----------------------------------------------------------------- 248 250 214 - ----------------------------------------------------------------- State -- Current 26 35 37 Deferred 16 7 (2) - ----------------------------------------------------------------- 42 42 35 - ----------------------------------------------------------------- Total $290 $292 $249 =================================================================
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:
2003 2002 ------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $1,204 $1,081
Property basis differences 401 381 Premium on reacquired debt 42 39 Pensions 117 103 Other 29 38 - ----------------------------------------------------------------- Total 1,793 1,642 - ----------------------------------------------------------------- Deferred tax assets: Capacity prepayments 8 11 Other deferred costs 13 13 Postretirement benefits 14 18 Unbilled revenue 21 20 Other 86 87 - ----------------------------------------------------------------- Total 142 149 - ----------------------------------------------------------------- Total deferred tax liabilities, net 1,651 1,493 Portion included in current liabilities, net (80) (56) - ----------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $1,571 $1,437 =================================================================
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 $11 million in each of 2003, 2002, and 2001. At December 31, 2003, all investment tax credits available to reduce federal income taxes payable had been utilized.
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
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2003 2002 2001 -------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.5 3.5 3.5 Non-deductible book depreciation 1.2 1.3 1.5 Differences in prior years' deferred and current tax rates (0.9) (1.2) (1.3) Other (1.6) (0.5) (0.5) - --------------------------------------------------------------- Effective income tax rate 37.2% 38.1% 38.2% ===============================================================
6. FINANCING
Mandatorily Redeemable Preferred Securities
The Company has formed certain wholly owned trust subsidiaries for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to the Company through the issuance of junior subordinated notes totaling $309 million, which constitute substantially all assets of these trusts. 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, 2003, preferred securities of $300 million were outstanding and recognized as liabilities in the Balance Sheets. For additional information, see the Statements of Capitalization.
First Mortgage Bonds
In October 1991, the Company entered into a firm power sales contract with the Alabama Municipal Electric Authority (AMEA) entitling AMEA to scheduled amounts of capacity (up to a maximum 80 megawatts) for a period of 15 years. Under the terms of the contract, the Company received payments from AMEA representing the net present value of the revenues associated with the capacity entitlement, discounted at an effective annual rate of 11.19 percent. These payments are being recognized as operating revenues and the discount is amortized to other interest expense as scheduled capacity is made available over the terms of the contract.
To secure AMEA's advance payments and the Company's performance obligation under the contracts, the Company issued and delivered to an escrow agent first mortgage bonds representing the maximum amount of liquidated damages payable by the Company in the event of a default under the contracts. No principal or interest is payable on such bonds unless and until a default by the Company occurs. As the liquidated damages decline, a portion of the bond equal to the decrease is returned to the Company. At December 31, 2003, $26.7 million of these bonds were held by the escrow agent under the contract.
Pollution Control Bonds
Pollution control obligations represent installment purchases of pollution control facilities financed by funds derived from sales by public authorities of revenue bonds. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. With respect to $114.2 million of such pollution control obligations, the Company has authenticated and delivered to the trustees a like principal amount of first mortgage bonds as security for its obligations under the installment purchase agreements. No principal or interest on these first mortgage bonds is payable unless and until a default occurs on the installment purchase agreements.
Senior Notes
The Company issued a total of $1.4 billion of unsecured senior notes in 2003. The proceeds of these issues were used to redeem higher cost debt and for other general corporate purposes.
At December 31, 2003 and 2002, the Company had $3.4 billion of senior notes outstanding. These senior notes are subordinate to all secured debt of the Company which amounted to approximately $295 million at December 31, 2003.
Long-Term Debt Due Within One Year
A summary of the improvement fund requirements and scheduled maturities and redemptions of long-term debt due within one year at December 31 is as follows:
2003 2002 ----------------------- (in millions) Capitalized leases $ 1 $ 1 Senior notes 525 1,117 ------------------------------------------------- ----------- Total $526 $1,118 =============================================================
Debt redemptions and/or serial maturities through 2008 applicable to total long-term debt are as follows: $526 million in 2004; $225 million in 2005; $715 million in 2006; $200 million in 2007; and $410 million in 2008.
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NOTES (continued) Alabama Power Company 2003 Annual Report
Assets Subject to Lien
The Company's mortgage, as amended and supplemented, securing the first mortgage bonds issued by the Company, constitutes a direct lien on substantially all of the Company's fixed property and franchises.
Bank Credit Arrangements
The Company maintains committed lines of credit in the amount of $865 million (including $504 million of such lines which are dedicated to funding purchase obligations relating to variable rate pollution control bonds), all of which expire at various times during 2004. Approximately $450 million of the credit facilities expiring in 2004 allow for the execution of term loans for an additional two-year period, and $245 million allow for the execution of one-year term loans. All of the credit arrangements require payment of a commitment fee based on the unused portion of the commitment or the maintenance of compensating balances with the banks. Commitment fees are less than 1/4 of 1 percent for the Company. Because the arrangements are based on an average balance, the Company does not consider any of its cash balances to be restricted as of any specific date. For syndicated credit arrangements, a fee is also paid to the agent bank.
Most of the Company's credit arrangements with banks have covenants that limit the Company's debt to 65 percent of total capitalization, as defined in the agreements. Exceeding this debt level would result in a default under the credit arrangements. At December 31, 2003, 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. As of December 31, 2003, the Company had no extendible commercial notes and no commercial paper outstanding. The amount of commercial paper outstanding at December 31, 2002 was $37 million. During 2003, the peak amount outstanding for commercial paper was $255 million and the average amount outstanding was $30 million. The average annual interest rate on commercial paper in 2003 was 1.29 percent. Commercial paper and extendible commercial notes are included in notes payable on the Balance Sheets.
At December 31, 2003, the Company had regulatory approval to have outstanding up to $1 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.
At December 31, 2003, the fair value of derivative energy contracts was reflected in the financial statements as follows:
Amounts ------------ (in thousands) Regulatory liabilities, net $6,402 Net income 11 - ------------------------------------------------------------ Total fair value $6,413 ============================================================
The fair value gain or loss for cash flow 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 also enters into derivatives to hedge exposure of interest rate changes. Interest derivatives related to variable rate securities or forecasted transactions are accounted for as cash flow hedges. The interest derivatives are generally structured to match the critical terms of the hedged debt instruments; therefore, no material ineffectiveness has been recorded in earnings.
At December 31, 2003, the Company had $1.2 billion notional amount of interest rate swaps outstanding with net deferred gains of $5.7 million as follows:
Cash Flow Hedges Weighted Average -------------------- Fair Fixed Value Rate Notional Gain/ Maturity Paid Amount (Loss) - ------------------------------------ -------------------- (in millions) 2004 1.63* $486 $(0.2) 2006 1.89 195 1.5 2007 1.99* 486 4.4 - ----------------------------------------------------------- *Hedged using the Bond Market Association Municipal Swap Index.
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NOTES (continued) Alabama Power Company 2003 Annual Report
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 2003 and 2002, the Company recognized losses of $8 million and $13 million, respectively, upon termination of certain interest derivatives at the same time it issued debt. These losses have been deferred in other comprehensive income and will be amortized to interest expense over the life of the related debt. For 2003, approximately $11.3 million of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2004, pre-tax losses of approximately $5.8 million are expected to be reclassified from other comprehensive income to interest expense.
7. COMMITMENTS
Construction Program
The Company is engaged in continuous construction programs, currently estimated to total $791 million in 2004, $863 million in 2005, and $884 million in 2006. These amounts include $12.5 million, $11.3 million, and $6.6 million in 2004, 2005, and 2006, respectively, for construction expenditures related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included in this note 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 regulations; changes in existing nuclear plants to meet new regulatory requirements; changes in FERC rules and transmission regulations; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2003, 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.
Southern Company has guaranteed Southern Power's obligations to the Company for transmission interconnection facilities of $6.8 million related to Plant Harris units 1 & 2. The obligations were guaranteed at December 31, 2003, but, upon completion of construction, were released in February 2004.
Long-Term Service Agreements
The Company has entered into several Long-Term Service Agreements (LTSAs) with General Electric (GE) for the purpose of securing maintenance support for its combined cycle and combustion turbine generating facilities. The LTSAs stipulate that GE will perform all planned maintenance on the covered equipment, which includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in each contract.
In general, these LTSAs are in effect through two major inspection cycles per unit. Scheduled payments to GE are made at various intervals based on actual operating hours of the respective units. Total payments to GE under these agreements are currently estimated at $253 million over the life of the agreements, which are approximately 12 to 14 years per unit. At December 31, 2003, the remaining balance was approximately $213 million. However, the LTSAs contain various cancellation provisions at the option of the Company.
Payments made to GE prior to the performance of any planned maintenance are recorded as a prepayment 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, 2003 were as follows:
Commitments ------------------------------------ Non- Year Affiliated Affiliated Total - ---- ------------------------------------ (in millions) 2004 $ 49 $ 36 $ 85 2005 49 38 87 2006 49 39 88 2007 49 40 89 2008 49 40 89 2009 and thereafter 62 67 129 - --------------------------------------------------------------- Total commitments $307 $260 $567 ===============================================================
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NOTES (continued) Alabama Power Company 2003 Annual Report
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Natural gas purchase commitments contain 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 future prices at December 31, 2003. Total estimated minimum long-term commitments at December 31, 2003 were as follows:
Coal & Natural Nuclear Year Gas Fuel - ---- --------------------------- (in millions) 2004 $ 318 $ 750 2005 181 514 2006 158 437 2007 107 429 2008 26 154 2009 and thereafter 108 - - ------------------------------------------------------------- Total commitments $ 898 $2,284 ==============================================================
Additional commitments for fuel will be required to supply the Company's future needs.
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company retail operating companies, Southern Power, and Southern Company GAS. Under these agreements, each of the retail operating companies, Southern Power, and Southern Company GAS may be jointly and severally liable. The creditworthiness of Southern Power and Southern Company GAS is currently inferior to the creditworthiness of the retail operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other retail operating companies to insure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power or Southern Company GAS as a contracting party under these agreements.
Operating Leases
The Company has entered into rental agreements for coal rail cars, vehicles, and other equipment with various terms and expiration dates. These expenses totaled $29.5 million in 2003, $29.6 million in 2002, and $27.9 million in 2001. Of these amounts, $19.4 million, $19.1 million, and $21.1 million for 2003, 2002, and 2001, respectively, relates to the rail car leases and are recoverable through the Company's energy cost recovery clause. At December 31, 2003, estimated minimum rental commitments for noncancellable operating leases were as follows:
Rail Vehicles Year Cars & Other Total - --------------------------------------------------------------- (in millions) 2004 $19.1 $10.6 $29.7 2005 16.3 8.9 25.2 2006 11.3 6.2 17.5 2007 4.1 3.6 7.7 2008 3.8 2.0 5.8 2009 and thereafter 30.7 4.5 35.2 - --------------------------------------------------------------- Total minimum payments $85.3 $35.8 $121.1 ===============================================================
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 2004 and 2006, and the Company's maximum obligations are $25.7 million and $66.0 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 reduce or eliminate the Company's payments under the residual value obligations.
Guarantees
At December 31, 2003, the Company had outstanding guarantees related to SEGCO's purchase of certain pollution control facilities, as discussed in Note 4, and to certain residual values of leased assets. See "Operating Leases" above.
8. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988 (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 $10.9 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 $100.5 million per incident for
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NOTES (continued) Alabama Power Company 2003 Annual Report
each licensed reactor it operates but not more than an aggregate of $10 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 $20 million to be paid for each incident in any one year. The Price-Anderson Amendments Act expired in August 2002; however, the indemnity provisions of the act remain in place for commercial nuclear reactors.
The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members' nuclear generating facilities.
Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.
NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After this deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. The Company purchases the maximum limit allowed by NEIL and has elected a 12 week waiting period.
Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for the Company under the NEIL policies would be $36 million.
Following the terrorist attacks of September 2001, both ANI and NEIL confirmed that terrorist acts against commercial nuclear power plants would be covered under their insurance. However, both companies revised their policy terms on a prospective basis to include an industry aggregate for all "non-certified" terrorist acts, i.e., acts that are not certified acts of terrorism pursuant to the Terrorism Risk Insurance Act of 2002 (TRIA). The NEIL aggregate -- applies to all non-certified claims stemming from terrorism within a 12 month duration -- is $3.24 billion plus any amounts available through reinsurance or indemnity from an outside source. The non-certified ANI cap is a $300 million shared industry aggregate. Any act of terrorism that is certified pursuant to the TRIA will not be subject to the foregoing NEIL and ANI limitations but will be subject to the TRIA annual aggregate limitation of $100 billion of insured losses arising from certified acts of terrorism. The TRIA will expire on December 31, 2005.
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.
9. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for 2003 and 2002 are as follows:
Net Income After Dividends Quarter Operating Operating on Preferred Ended Revenues Income Stock - -------------------- ------------------------------------------- (in millions)
March 2003 $ 890 $211 $ 92 June 2003 950 227 107 September 2003 1,216 414 217 December 2003 904 163 57
March 2002 $ 802 $191 $ 72 June 2002 924 256 116 September 2002 1,119 393 201 December 2002 865 182 72 - -----------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions.
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GEORGIA POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Georgia Power Company 2003 Annual Report
The management of Georgia Power Company has prepared -- and is responsible for - -- the financial statements and related information included in this report. These statements were prepared in accordance with accounting principles generally accepted in the United States and necessarily include amounts that are based on the best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that the accounting records reflect only authorized transactions of the Company. Limitations exist in any system of internal controls, however, based upon recognition that the cost of the system should not exceed its benefits. The Company believes its system of internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's internal accounting controls are evaluated on an ongoing basis by the Company's internal audit staff. The Company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements.
Southern Company's audit committee of its board of directors, composed of four independent directors, provides a broad overview of management's financial reporting and control functions. Additionally, the Controls and Compliance Committee of the Company's board of directors, composed of a minimum of three outside directors, meets periodically with management, the internal auditors, and the independent public accountants to discuss auditing, internal controls, and compliance matters. The internal auditors and independent public accountants have access to the members of these committees at any time.
Management believes that its policies and procedures provide reasonable assurance that the Company's operations are conducted with a high standard of business ethics.
In management's opinion, the financial statements present fairly, in all material respects, the financial position, results of operations and cash flows of Georgia Power Company in conformity with accounting principles generally accepted in the United States.
/s/David M. Ratcliffe David M. Ratcliffe Chief Executive Officer
/s/Michael D. Garrett Michael D. Garrett President
/s/C. B. Harreld C. B. Harreld Executive Vice President, Treasurer, and Chief Financial Officer March 1, 2004
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INDEPENDENT AUDITORS' REPORT
Georgia Power Company:
We have audited the accompanying balance sheets and statements of capitalization of Georgia Power Company (a wholly owned subsidiary of Southern Company) as of December 31, 2003 and 2002, and the related statements of income, comprehensive income, common stockholder's equity, and cash flows of the years then ended. These financial statements are the responsibility of Georgia Power Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The financial statements of Georgia Power Company for the year ended December 31, 2001 were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements and included an explanatory paragraph that described a change in the method of accounting for derivative instruments and hedging activities in their report dated February 13, 2002.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, the financial statements (pages II-128 to II-154) present fairly, in all material respects, the financial position of Georgia Power Company at December 31, 2003 and 2002, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the financial statements, in 2003 Georgia Power Company changed its method of accounting for asset retirement obligations.
/s/Deloitte & Touche LLP Atlanta, Georgia March 1, 2004
THE FOLLOWING REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH THE COMPANY'S 2001 ANNUAL REPORT AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP. SEE EXHIBIT 23(c)2 FOR ADDITIONAL INFORMATION.
To Georgia Power Company:
We have audited the accompanying balance sheets and statements of capitalization of Georgia Power Company (a Georgia corporation and a wholly owned subsidiary of Southern Company) as of December 31, 2001 and 2000, 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, 2001. 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 auditing standards generally accepted in the 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, the financial statements (pages II-93 through II-113) referred to above present fairly, in all material respects, the financial position of Georgia Power Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
As explained in Note 1 to the financial statements, effective January 1, 2001, Georgia Power Company changed its method of accounting for derivative instruments and hedging activities.
/s/Arthur Andersen LLP Atlanta, Georgia February 13, 2002
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Georgia Power Company 2003 Annual Report
OVERVIEW OF EARNINGS AND BUSINESS - --------------------------------- ACTIVITIES - ----------
Earnings
Georgia Power Company's 2003 earnings totaled $631 million, representing a $13 million (2.1 percent) increase over 2002. Operating income increased in 2003 despite lower base retail revenues resulting from the extremely mild summer weather. Higher wholesale revenues and lower non-fuel operating expenses contributed to the increase. The Company's 2002 earnings totaled $618 million, representing an $8 million (1.2 percent) increase over 2001. Operating income declined slightly in 2002. Lower retail and wholesale revenues, higher other operating and maintenance expenses and increased purchased power capacity expenses were significantly offset by lower depreciation and amortization expense as a result of a Georgia Public Service Commission (GPSC) retail rate order effective January 2002. The increase in net income for 2002 resulted from lower financing costs and a lower effective tax rate due to the realization of certain state tax credits. The Company's 2001 earnings totaled $610 million, representing a $51 million (9.1 percent) increase over 2000. Operating income was lower in 2001 compared to 2000 due to the impact of mild weather on retail revenues; however, overall net income improved due to lower financing costs and non-operating expenses and a lower effective tax rate resulting from various factors including property donations and positive resolution of outstanding tax issues.
Business Activities
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.
Several factors affect the opportunities, challenges and risk of the Company's primary business of selling electricity. These factors include the ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly strict environmental standards. 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.
RESULTS OF OPERATIONS - ---------------------
A condensed income statement for the Company is as follows:
Increase (Decrease) Amount From Prior Year ------------------------------------------ 2003 2003 2002 2001 - ----------------------------------------------------------------- (in millions) Operating revenues $4,914 $ 92 $(144) $ 95 - ----------------------------------------------------------------- Fuel 1,104 101 64 (79) Purchased power 776 92 (87) 175 Other operation and maintenance 1,247 (78) 85 41 Depreciation and amortization 350 (54) (197) (19) Taxes other than income taxes 213 11 (1) (1) - ----------------------------------------------------------------- Total operating expenses 3,690 72 (136) 117 - ----------------------------------------------------------------- Operating income 1,224 20 (8) (22) Other income and (expense) (227) 2 9 76 Less - Income taxes 366 9 (7) 3 - ----------------------------------------------------------------- Net income $ 631 $13 $ 8 $ 51 =================================================================
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2003 Annual Report
Revenues
Operating revenues in 2003, 2002, and 2001 and the percent of change from the prior year are as follows:
Amount ------------------------------------ 2003 2002 2001 ------------------------------------ (in millions) Retail - prior year $4,288 $4,349 $4,317 Change in - Base rates - (118) - Sales growth and other 30 2 90 Weather (66) 82 (107) Fuel cost recovery and other 58 (27) 49 - -------------------------------------------------------------------- Retail - current year 4,310 4,288 4,349 - -------------------------------------------------------------------- Sales for resale - Non-affiliates 260 271 366 Affiliates 175 98 100 - -------------------------------------------------------------------- Total sales for resale 435 369 466 - -------------------------------------------------------------------- Other operating revenues 169 165 151 - -------------------------------------------------------------------- Total operating revenues $4,914 $4,822 $4,966 ==================================================================== Percent change 1.9% (2.9)% 2.0% - --------------------------------------------------------------------
Retail base revenues of $3.0 billion in 2003 decreased by $36 million (1.2 percent) from 2002 primarily due to extremely mild summer temperatures in 2003 and the sluggish economy. Residential kilowatt-hour (KWH) sales decreased by 1.7 percent. Retail base revenues of $3.1 billion in 2002 decreased by $34 million (1.1 percent) from 2001 primarily due to a base rate reduction effective January 2002 under the GPSC retail rate order and generally lower prices to large business customers. This decrease was partially offset by a 10.1 percent increase in residential KWH sales due to warmer weather. Retail base revenues of $3.1 billion in 2001 decreased $17 million (0.5 percent) from 2000, primarily due to a 2.5 percent decrease in retail KWH sales from the prior year. Milder-than-normal weather and a slowdown in the economy contributed to the decline in such sales.
Electric rates include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses -- including the fuel component of purchased energy -- and do not affect net income. As of December 31, 2003, the Company had $151 million in under-recovered fuel costs. On August 19, 2003, the GPSC issued an order allowing the Company to increase customer fuel rates to recover existing under-recovered deferred fuel costs. See Note 3 to the financial statements under "Fuel Cost Recovery" for further information regarding this order.
Wholesale revenues from sales to non-affiliated utilities were:
2003 2002 2001 ------------------------------ (in millions) Unit power sales -- Capacity $ 34 $ 34 $ 26 Energy 31 34 35 Other power sales -- Capacity 38 41 72 Energy 157 162 233 - -------------------------------------------------------------- Total $260 $271 $366 ==============================================================
Revenues from unit power contracts decreased slightly in 2003 due to decreased energy sales. Approximately 103 megawatts of capacity is scheduled to be sold annually through 2010. Revenues from other non-affiliated sales decreased $8 million (3.9 percent) in 2003, decreased $102 million (33.4 percent) in 2002 and increased $62 million in 2001 primarily due to fluctuations in off-system sale transactions that were generally offset by corresponding purchase transactions. These transactions had no significant effect on income. In 2002, revenues also decreased $37 million as a result of transferring Plant Dahlberg to Southern Power Company (Southern Power) in July 2001.
Revenues from sales to affiliated companies within the Southern Company electric system, as well as purchases of energy, will vary from year to year depending on demand and the availability and cost of generating resources at each company. In 2003, energy sales to affiliates increased 47.5 percent due to the combination of increased demand by Southern Power to meet contractual obligations and the availability of power due to milder-than-normal weather in the Company's service territory. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
Other operating revenues increased $4 million (2.4 percent) in 2003 primarily due to an increase in the open access transmission tariff rate, which increased revenues $7 million, and higher revenues from increased customer demand for outdoor lighting services of $4 million, partially offset by lower revenue from the rental of electric property of $4 million. See Note 3 to the financial statements under "Open Access Transmission Tariff" for further
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2003 Annual Report
information regarding the increase in the open access transmission tariff rate. Other operating revenues in 2002 increased $14 million (9.5 percent) primarily due to the collection of new late payment fees approved under the retail rate order effective January 2002 of $7 million and higher revenues from increased customer demand for outdoor lighting services of $5 million and the transmission of electricity of $3 million. Other operating revenues in 2001 decreased $9 million (5.3 percent) primarily due to lower gains on the sale of generating plant emission allowances, partially offset by increased revenues from the transmission of electricity and from the rental of electric equipment and property.
Energy Sales
KWH sales for 2003 and the percent change by year were as follows:
KWH Percent Change ----------------------------------------- 2003 2003 2002 2001 ----------------------------------------- (in billions) Residential 21.8 (1.7)% 10.1% (2.8)% Commercial 26.9 (0.1) 1.7 3.4 Industrial 25.7 (0.1) 1.5 (8.0) Other 0.6 0.4 1.7 2.5 -------- Total retail 75.0 (0.5) 4.0 (2.5) -------- Sales for resale - Non-affiliates 8.9 9.5 (0.5) 25.5 Affiliates 5.8 47.5 26.5 28.7 -------- Total sales for resale 14.7 22.0 7.0 26.3 -------- Total sales 89.7 2.6 4.4 0.5 ================================================================
Residential KWH sales decreased 1.7 percent in 2003 due to the effect of the milder summer weather despite the 2 percent increase in residential customers. Commercial KWH sales declined slightly due to the milder summer weather, while industrial KWH sales declined slightly due to the sluggish economy. Residential KWH sales increased 10.1 percent in 2002 due to the effect of the warmer weather. Commercial and industrial KWH sales increased 1.7 percent and 1.5 percent, respectively, due to corresponding increases of 2.6 percent and 2.4 percent, respectively, in customers. Residential KWH sales decreased 2.8 percent in 2001 due to milder-than-normal weather. Commercial KWH sales increased 3.4 percent due to an increase in customers, while industrial KWH sales decreased 8.0 percent due to an economic slowdown. Retail sales growth assuming normal weather is expected to be 1.6 percent on average from 2004 to 2013.
Expenses
Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by system load, the unit cost of fuel consumed, and the availability of hydro and nuclear generating units. The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated were as follows:
2003 2002 2001 ------------------------------ Total generation (billions of KWH) 73.1 70.4 68.9 Sources of generation (percent) -- Coal 75.4 77.4 74.9 Nuclear 21.6 21.1 23.2 Hydro 2.7 1.2 1.4 Oil and gas 0.3 0.3 0.5 Average cost of fuel per net KWH generated (cents) -- 1.46 1.42 1.38 Average cost of purchased power per net KWH (cents) -- 4.03 3.29 3.79 - ------------------------------------------------------------------
Fuel expense increased 10.1 percent in 2003 due to an increase in generation of 3.9 percent because of higher wholesale energy demands and a 2.8 percent higher average cost of fuel due to the higher prices of coal and natural gas in 2003. Fuel expense increased 6.8 percent in 2002 due to a 2.2 percent increase in generation because of higher energy demands and a 2.9 percent higher average cost of fuel due to the higher cost of coal. In 2001, fuel expense decreased 7.7 percent due to a decrease in generation because of lower energy demands and a slightly lower average cost of fuel.
Purchased power expense increased $91 million (13.3 percent) in 2003 primarily due to $75 million of additional capacity expense associated with new purchased power contracts that went into effect in 2003 and 2002. Purchased power expense decreased $87 million (11.2 percent) in 2002 and increased $175 million (29.4 percent) in 2001 primarily due to fluctuations in off-system energy purchases used to meet off-system sales commitments. The 2002 decrease in energy purchases was partially offset by a $43 million increase in capacity expense associated with new purchased power contracts.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2003 Annual Report
In 2003, other operation and maintenance expenses decreased $78 million (5.9 percent) due to the timing of generating plant maintenance of $46 million and transmission and distribution maintenance of $8 million and lower severance costs of $8 million. In 2002, other operation and maintenance expenses increased $85 million (6.8 percent) due to the timing of generating plant maintenance of $44 million and transmission maintenance of $17 million, and increased property insurance expense of $5 million. In 2001, other operation and maintenance expenses increased $41 million (3.4 percent) due to additional severance costs, increased scheduled generating plant maintenance, and higher uncollectible account expense.
Depreciation and amortization decreased $54 million in 2003 primarily as a result of lower regulatory charges related to the inclusion of new certified purchased power costs in retail rates on a levelized basis as ordered by the GPSC. Depreciation and amortization decreased $197 million in 2002 primarily as a result of discontinuing accelerated depreciation, beginning amortization of the regulatory liability for accelerated cost recovery, and lowering the composite depreciation rates in January 2002 all in accordance with the retail rate order. Depreciation and amortization decreased $19 million in 2001 primarily due to lower accelerated amortization under the third year of a prior GPSC retail rate order. See Note 3 to the financial statements under "Retail Rate Orders" for additional information.
Taxes other than income taxes increased $11 million (5.4 percent) in 2003 due mainly to a favorable true-up of state property tax valuations in 2002. Taxes other than income taxes remained relatively constant in 2002.
Interest income increased $12 million in 2003 when compared to the prior year due to interest on a favorable income tax settlement of $14.5 million. Interest income remained relatively constant in 2002.
Interest expense increased in 2003 primarily related to an increase in senior notes outstanding that was partially offset by a reduction in short-term debt outstanding. Interest expense decreased in 2002 and 2001 primarily due to lower interest rates that offset new financing costs. The Company refinanced or retired $665 million, $929 million, and $775 million of securities in 2003, 2002, and 2001, respectively. Interest capitalized decreased in 2003 and 2002 due to the transfer of three new generation projects to Southern Power in 2002 and 2001. Interest capitalized increased in 2001 during the construction phase of these new projects. See Note 7 to the financial statements under "Construction Program" for additional information regarding the construction and subsequent transfer of these generation assets. Distributions on mandatorily redeemable preferred securities decreased in 2003 due to the redemption of securities in the second half of 2002 and increased in 2002 due to the issuance of additional securities while remaining unchanged in 2001.
Effects of Inflation
The Company is subject to rate regulation that is based on the recovery of historical costs. In addition, the income tax laws are also based on historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that 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 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 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 results of operations for the past three years are not necessarily indicative of future earnings. The level of future earnings depends on numerous factors including the Company's ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly strict environmental standards.
Growth in energy sales is subject to a number of factors which 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.
Industry Restructuring
The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in the State of
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Georgia and to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the GPSC under cost-based regulatory principles.
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 Policy Act of 1992 (Energy Act). The Energy Act allowed independent power producers to access a utility's transmission network and sell electricity to other utilities.
Although the Energy Act does not provide for retail customer access, it was a major catalyst for restructuring and consolidations that took place within the utility industry. Numerous federal and state initiatives that promote wholesale and retail competition are in varying stages. Among other things, these initiatives allow retail customers in some states to choose their electricity provider. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While various restructuring and competition initiatives have been discussed in Georgia, none have been enacted. Enactment could require numerous issues to be resolved, including significant ones relating to recovery of any stranded investments, full cost recovery of energy produced, and other issues related to the energy crisis that occurred in California, as well as the August 2003 power outage in the Northeast. The Company does compete with other electric suppliers within the state. In Georgia, most new retail customers with at least 900 kilowatts of connected load may choose their electricity supplier.
Since 2001, merchant energy companies and traditional electric utilities with significant energy marketing and trading activities have come under severe financial pressures. Many of these companies have completely exited or drastically reduced all energy marketing and trading activities and sold foreign and domestic electric infrastructure assets. The Company has not experienced any material financial impact regarding its limited energy trading operations through Southern Company Services (SCS).
Continuing to be a low-cost producer could provide opportunities to increase the size and profitability in markets that evolve with changing regulation and competition. Conversely, future regulatory changes could adversely affect the Company's growth, and if the Company does not remain a low-cost producer and provide quality service, then energy sales growth could be limited, and this could significantly erode earnings.
Environmental Matters
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action against the Company alleging the Company had violated the New Source Review (NSR) provisions of the Clean Air Act with respect to coal-fired generating facilities at the Company's Bowen and Scherer plants. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The action against the Company has been stayed since the spring of 2001 during the appeal of a very similar NSR action against the Tennessee Valley Authority before the U.S. Court of Appeals for the Eleventh Circuit. The Eleventh Circuit appeal was decided on September 16, 2003, and, on February 13, 2004, the EPA petitioned the U.S. Supreme Court to review the Eleventh Circuit's decision. At this time, no party to the Company's action, which was administratively closed two years ago, has asked the court to reopen that case. See Note 3 to the financial statements under "New Source Review Actions" for additional information.
In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. The December 2002 revisions included changes to the regulatory exclusions and the methods of calculating emissions increases. The October 2003 regulations clarified the scope of the existing Routine Maintenance Repair and Replacement exclusion. A coalition of states and environmental organizations filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. On December 24, 2003, the Court of Appeals granted a stay of the October 2003 revisions pending its review of the rules, and ordered that its review would be conducted on an expedited basis. In January 2004, the Bush Administration announced that it would continue to enforce the existing rules until the courts resolve legal challenges to the EPA's revised NSR regulations. In any event, the final
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regulations must be adopted by the State of Georgia in order to apply to the Company's facilities. The effect of these final regulations and the related legal challenges cannot be determined at this time.
The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome in this matter could require substantial capital expenditures and additional operation and maintenance expenses that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
Plant Wansley Environmental Litigation
On December 30, 2002, the Sierra Club, Physicians for Social Responsibility, Georgia ForestWatch, and one individual filed a civil suit in the U.S. District Court in Georgia against the Company for alleged violations of the Clean Air Act at four of the units at Plant Wansley. The civil action requests injunctive and declaratory relief, civil penalties, a supplemental environmental project, and attorneys' fees. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. This case is currently scheduled for trial during the summer of 2004. See Note 3 to the financial statements under "Plant Wansley Environmental Litigation" for additional information.
While the Company believes that it has complied with applicable laws and regulations, an adverse outcome could require payment of substantial penalties. The final outcome of this matter cannot now be determined.
Environmental Statutes and Regulations
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. Compliance with these environmental requirements will involve significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Environmental costs that are known and estimable at this time are included in capital expenditures under "Capital Requirements and Contractual Obligations." There is no assurance, however, that all such costs will, in fact, be recovered.
Compliance with the federal Clean Air Act and resulting regulations has been, and will continue to be, a significant focus for the Company. The Title IV acid rain provisions of the Clean Air Act, for example, required significant reductions in sulfur dioxide and nitrogen oxide emissions. Title IV compliance was effective in 2000 and associated construction expenditures totaled approximately $206 million. Some of these expenditures also assisted the Company in complying with nitrogen oxide emission reduction requirements under Title I of the Clean Air Act, which were designed to address one-hour ozone nonattainment problems in Atlanta, Georgia. The State of Georgia adopted regulations that required additional nitrogen oxide emission reductions from May through September of each year at plants in and/or near those nonattainment areas. Seven generating plants in the Atlanta area are currently subject to those requirements, the most recent of which went into effect in 2003. Construction expenditures for compliance with the nitrogen oxide emission reduction requirements are estimated to be $698 million, of which $17 million remains to be spent.
On September 26, 2003, the EPA published a final rule effective January 1, 2004 reclassifying the Atlanta area from a "serious" to a "severe" nonattainment area for the one-hour ozone air quality standard under Title I of the Clean Air Act. The attainment deadline is to be as expeditious as practicable but not later than November 15, 2005. If the Atlanta area fails to comply with the one-hour ozone standard by the deadline, all major sources of nitrogen oxides and volatile organic compounds located in the nonattainment area, including the Company's plants McDonough and Yates, could be subject to payment of annual emissions fees for nitrogen oxides emitted above 80 percent of the baseline period. The baseline period is expected to be the calendar year 2005. Based on average emissions at these units over the past three years, such fees could reach $23 million annually. The final outcome of this matter will depend on the baseline period selected and the development, approval, and implementation of applicable regulations including new regulations for the eight-hour ozone air quality standard.
To help ozone nonattainment areas attain the one-hour ozone standard, the EPA issued regional nitrogen oxide reduction rules in 1998. Those rules required 21 states, including Georgia, to reduce and cap nitrogen oxide emissions from
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power plants and other large industrial sources. As a result of litigation challenging the rule, the courts required the EPA to complete a separate rulemaking before the requirements can be applied in Georgia. The final EPA rules have not been issued in Georgia. The impact of this rule on the Company will depend on the form in which it is finalized and cannot be determined at this time.
In July 1997, the EPA revised the national ambient air quality standards for ozone and particulate matter. These revisions made the standards significantly more stringent. In the subsequent litigation of these standards, the U.S. Supreme Court found the EPA's implementation program for the new eight-hour ozone standard unlawful and remanded it to the EPA for further rulemaking. During 2003, the EPA proposed implementation rules designed to address the court's concerns. The EPA plans to designate areas as attainment or nonattainment with the new eight-hour ozone standard in April 2004 and with the new fine particulate matter standard by the end of 2004. These designations will be based on air quality data for 2001 through 2003. Several areas within the Company's service area are likely to be designated nonattainment under these standards. State implementation plans (SIPs), including new emission control regulations necessary to bring those areas into attainment, could be required as early as 2007. Those SIPs could require reductions in sulfur dioxide emissions and could require further reductions in nitrogen oxide emissions from power plants. If so, reductions could be required sometime after 2007. The impact of any new standards will depend on the development and implementation of applicable regulations and cannot be determined at this time.
In January 2004, the EPA issued a proposed Interstate Air Quality Rule to address interstate transport of ozone and fine particles. This proposed rule would require additional year-round sulfur dioxide and nitrogen oxide emission reductions from power plants in the eastern United States in two phases - in 2010 and 2015. The EPA currently plans to finalize this rule by 2005. If finalized, the rule could modify or supplant other SIP requirements for attainment of the fine particulate matter standard and the eight-hour ozone standard. The impact of this rule on the Company will depend upon the specific requirements of the final rule and cannot be determined at this time.
Further reductions in sulfur dioxide and nitrogen oxides could also be required under the EPA's Regional Haze rules. The Regional Haze rules require states to establish Best Available Retrofit Technology (BART) standards for certain sources that contribute to regional haze. The Company has a number of plants that could be subject to these rules. The EPA's regional haze program calls for states to submit SIPs in 2007. The SIPs must contain emission reduction strategies for implementing BART and achieving progress toward the Clean Air Act's visibility improvement goal. In 2002, however, the U.S. Court of Appeals for the District of Columbia Circuit vacated and remanded the BART provisions of the federal Regional Haze rules to the EPA for further rulemaking. The EPA has entered into an agreement that requires proposed revised rules in April 2004 and final rules in 2005. Because new BART rules have not been developed and state visibility assessments for progress are only beginning, it is not possible to determine the effect of these rules on the Company at this time.
The EPA's Compliance Assurance Monitoring (CAM) regulations under Title V of the Clean Air Act require that monitoring be performed to ensure compliance with emissions limitations on an ongoing basis. In 2004 and 2005, a number of the Company's plants will likely be subject to CAM requirements for at least one pollutant, in most cases, particulate matter. The Company is in the process of developing CAM plans. Because the plans are still under development, the Company cannot determine the costs associated with implementation of the CAM regulations. Actual ongoing monitoring costs are expensed as incurred and are not material for any year presented.
In January 2004, the EPA issued proposed rules regulating mercury emissions from electric utility boilers. The proposal solicits comments on two possible approaches for the new regulations - a Maximum Achievable Control Technology approach and a cap-and-trade approach. Either approach would require significant reductions in mercury emissions from Company facilities. The regulations are scheduled to be finalized by the end of 2004, and compliance could be required as early as 2007. Because the regulations have not been finalized, the impact on the Company cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent emissions limitations on power plants have been proposed by Congress. Three of
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these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2003, and the Clean Air Planning Act of 2003, propose to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills also propose to limit emissions of carbon dioxide. The cost impacts of such legislation would depend upon the specific requirements enacted and cannot be determined at this time.
Domestic efforts to limit greenhouse gas emissions have been spurred by international discussions surrounding the Framework Convention on Climate Change and specifically the Kyoto Protocol, which proposes international constraints on the emissions of greenhouse gases. The Bush Administration does not support U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation and has instead announced a new voluntary climate initiative, known as Climate VISION, which seeks an 18 percent reduction by 2012 in the rate of greenhouse gas emissions relative to the dollar value of the U.S. economy. Through Southern Company, the Company is involved in a voluntary electric utility industry sector climate change initiative in partnership with the government. The electric utility sector has pledged to reduce its greenhouse gas intensity 3 to 5 percent over the next decade, and is in the process of developing a memorandum of understanding with the Department of Energy (DOE) to cover this voluntary program.
The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up and monitor known sites. Amounts expensed for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for a portion or all required cleanup costs for additional sites that may require environmental remediation. Under GPSC ratemaking provisions, $21 million has been deferred in a regulatory liability account for use in meeting future environmental remediation costs. See Note 3 to the financial statements under "Potentially Responsible Party Status" for information regarding the Company's potentially responsible party status at sites in Georgia.
Under the Clean Water Act, the EPA has been developing new rules aimed at reducing impingement and entrainment of fish and fish larvae at power plants' cooling water intake structures. On February 16, 2004, the EPA finalized these rules. These rules will require numerous biological studies, and, perhaps, retrofits to some intake structures at existing power plants. The impact of these new rules will depend on the results of studies and analyses performed as part of the rules' implementation.
The Company is also planning to install cooling towers at some of its facilities to cool water prior to discharge under the Clean Water Act. Cooling towers for two plants near Atlanta are scheduled for completion in 2004 and 2008 at an estimated total of $160 million, of which $90 million remains to be spent. Also, the Company is conducting a study of the aquatic environment at another facility to determine if additional controls are necessary.
In addition, under the Clean Water Act, the EPA and the State of Georgia Environmental Protection Division (EPD) are developing total maximum daily loads (TMDLs) for certain impaired waters. Establishment of maximum loads by the EPA or EPD may result in lowering permit limits for various pollutants and a requirement to take additional measures to control non-point source pollution (e.g., storm water runoff) at facilities that discharge into waters for which TMDLs are established. Because the effect on the Company will depend on the actual TMDLs and permit limitations established by the implementing agency, it is not possible to determine the effect on the Company at this time.
Several major pieces of environmental legislation are periodically considered for reauthorization or amendment by Congress. These 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 possible additional federal or state legislation or regulations related to global climate change, electromagnetic fields, or other environmental and health concerns could also significantly affect the Company. The impact of any new legislation, changes to existing legislation, or
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environmental regulations could affect many areas of the Company's operations. The full impact of any such changes cannot, however, be determined at this time.
FERC Matters
Transmission
In December 1999, the Federal Energy Regulatory Commission (FERC) issued its final rule (Order 2000) on Regional Transmission Organizations (RTOs). Order 2000 encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Through Southern Company, the Company worked with a number of utilities in the Southeast to develop a for-profit RTO known as SeTrans. In 2002, the sponsors of SeTrans established a Stakeholder Advisory Committee to provide input into the development of the RTO from other sectors of the electric industry, as well as consumers. During the development of SeTrans, state regulatory authorities expressed concern over certain aspects of the FERC's policies regarding RTOs. In December 2003, the SeTrans sponsors announced that they would suspend work on SeTrans because the regulated utility participants, including the Company, had determined that it was highly unlikely to obtain support of both federal and state regulatory authorities. Any impact of the FERC's rule on the Company will depend on the regulatory reaction to the suspension of SeTrans and future developments, which cannot now be determined.
In July 2002, the FERC issued a notice of proposed rulemaking regarding open access transmission service and standard electricity market design. The proposal, if adopted, would among other things: (1) require transmission assets of jurisdictional utilities to be operated by an independent entity; (2) establish a standard market design; (3) establish a single type of transmission service that applies to all customers; (4) assert jurisdiction over the transmission component of bundled retail service; (5) establish a generation reserve margin; (6) establish bid caps for day ahead and spot energy markets; and (7) revise the FERC policy on the pricing of transmission expansions. Comments on the proposal were submitted by many interested parties, including Southern Company, and the FERC has indicated that it has revised certain aspects of the proposal in response to public comments. Proposed energy legislation would prohibit the FERC from issuing the final rule before October 31, 2006, and from making any final rule effective before December 31, 2006. That legislation has been approved by the House of Representatives but remains pending before the Senate. Passage of the legislation now appears in doubt. It is uncertain whether in the absence of legislation the FERC will move forward with any part or all of the proposed rule. Any impact of this proposal on the Company will depend on the form in which the final rule may be ultimately adopted. However, the Company's financial statements could be adversely affected by changes in the transmission regulatory structure in its regional power market.
Market-Based Rate Authority
The Company has obtained FERC approval to sell power to non-affiliates at market-based prices under specific contracts. Through SCS, as agent, the Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities' applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company's retail operating companies, and found them to be "pivotal suppliers" in their control area market and ordered the implementation of several mitigation measures. SCS, on behalf of the Company and the other retail operating companies, sought rehearing of the FERC order and the FERC delayed implementation of certain mitigation measures. SCS, on behalf of the Company and the other retail operating companies, submitted comments to the FERC in 2002 regarding these issues. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. The Company anticipates that the FERC will address the requests for rehearing in the near future. Regardless of the outcome of the SMA proposal, the FERC retains the ability to modify or withdraw the authorization for any seller to sell at market-based rates, if it determines that the underlying conditions for having such authority are no longer applicable. The final outcome of this matter will depend on the form in which the SMA test and mitigation measures rules may be ultimately adopted and cannot be determined at this time.
Purchased power agreements (PPAs) by the Company and Savannah Electric for Southern Power's Plant McIntosh capacity were certified by the GPSC in December 2002 after a competitive bidding process. In April 2003, Southern Power applied
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for FERC approval of the PPAs. Interveners have made filings in opposition of the FERC's acceptance of the PPAs, alleging that the PPAs do not meet the applicable standards for market-based rates between alliliates. In July 2003, the FERC accepted the PPAs to become effective as scheduled on June 1, 2005, subject to refund, and ordered that hearings be held. For additional information, see Note 3 to the financial statements under "FERC Matters."
Other Matters
The Company is currently operating under a GPSC approved three-year retail rate order ending December 31, 2004. Under the terms of the order, earnings are evaluated annually against a retail return on common equity range of 10 percent to 12.95 percent. Two-thirds of any earnings above the 12.95 percent return are applied to rate refunds with the remaining one-third retained by the Company. The Company is required to file a general rate case on July 1, 2004, in response to which the GPSC would be expected to determine whether the rate order should be continued, modified, or discontinued. See Note 3 to the financial statements under "Retail Rate Orders" for additional information.
The Company has entered into various long-term PPAs which will result in higher capacity and operating and maintenance payments in future years. These agreements have been certified by the GPSC under Georgia's Integrated Resource Plan statute. Once certified, these costs are recoverable in rates under the statute. See Notes 3 and 7 to the financial statements under "Retail Rate Orders" and "Fuel and Purchased Power Commitments," respectively, for additional information.
On December 24, 2002, the GPSC approved an order allowing the Company to implement a natural gas and oil procurement and hedging program effective January 1, 2003. This order allows the Company to use financial instruments to hedge price and commodity risk associated with these fuels. The order limits the program 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 mechanism. Annual net financial gains from the hedging program will be shared with the retail customers receiving 75 percent and the Company retaining 25 percent of the net gains. There were no net gains in 2003.
In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash pension income, before tax, of approximately $54 million, $59 million, and $60 million in 2003, 2002, and 2001, respectively. Future pension income is dependent on several factors including trust earnings and changes to the plan. The decline in pension income is expected to continue and to become an expense by as early as 2007. Postretirement benefit costs for the Company were $41 million, $43 million and $43 million in 2003, 2002, and 2001, respectively, and are expected to trend upward. A portion of pension and postretirement benefit costs is capitalized based on construction-related labor charges. For the Company, pension income and postretirement benefit costs are a component of the regulated rates and generally do not have a significant long-term effect on net income. For additional information, see Note 2 to the financial statements.
On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act introduces a prescription drug benefit for Medicare-eligible retirees starting in 2006, as well as a federal subsidy to plan sponsors like the Company that provide prescription drug benefits. In accordance with FASB Staff Position No. 106-1, the Company has elected to defer recognizing the effects of the Medicare Act for its postretirement plans under FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other than Pension until authoritative guidance on accounting for the federal subsidy is issued or until a significant event occurs that would require remeasurement of the plans' assets and obligations. The Company anticipates that the benefits it pays after 2006 will be lower as a result of the Medicare Act; however, the retiree medical obligations and costs reported in Note 2 to the financial statements do not reflect these changes. The final accounting guidance could require changes to previously reported information.
Nuclear security legislation was recently introduced and considered in Congress both as a free-standing bill in the Senate and as a part of comprehensive energy legislation in a House-Senate Conference Report. Neither of the proposals has been enacted. The Nuclear Regulatory Commission (NRC) also has ordered additional security measures for licensees in 2003. The Company is in the process of implementation and must be in full compliance with these orders by October 29, 2004. The requirements of the latest orders will have an impact
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on the Company's nuclear power plants and result in increased operation and maintenance expenses as well as additional capital expenditures. The precise impact of the new requirements will depend upon the details of the implementation of the new requirements, which have not been finalized.
The Georgia General Assembly has recently adopted legislation that changes the law concerning condemnation of land for electric transmission lines. The legislation requires that a utility planning to construct or expand a transmission line hold public meetings in each county where the line would be located and that the utility attempt to negotiate a settlement with each affected property owner. The legislation also provides for the reconveyance of property interests that are condemned for a transmission line but are not used for that purpose within a specified number of years. The legislation, unless vetoed by Governor Perdue, will become effective on July 1, 2004.
The Company is involved in various matters being litigated, regulatory matters, and related issues that could affect future earnings. 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 discussed the development and selection of the critical accounting policies and estimates described below with the Controls and Compliance Committee of the Company's Board of Directors and the Audit Committee of Southern Company's Board of Directors.
Electric Utility Regulation
The Company is subject to retail regulation by the GPSC 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. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of Statement No. 71 has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on the Company's results of operations than they would on a non-regulated company.
As reflected in Note 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. However, adverse legislation and 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" 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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o 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. o Changes in existing income tax regulations or changes in Internal Revenue Service interpretations of existing regulations. o 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. o Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant. o Resolution or progression of existing matters through the legislative process, the court systems, the EPA, or the EPD.
New Accounting Standards
Prior to January 2003, the Company accrued for the ultimate cost of retiring most long-lived assets over the life of the related asset through depreciation expense. FASB Statement No. 143, Accounting for Asset Retirement Obligations, established new accounting and reporting standards for legal obligations associated with the ultimate cost of retiring long-lived assets. 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. Additionally, non-regulated companies are no longer permitted to continue accruing future retirement costs for long-lived assets that they do not have a legal obligation to retire. For additional information regarding the impact of adopting this standard effective January 1, 2003, see Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal."
FASB Statement No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, which further amends and clarifies the accounting and reporting for derivative instruments, became effective generally for financial instruments entered into or modified after June 30, 2003. Current interpretations of Statement No. 149 indicate that certain electricity forward transactions subject to unplanned netting --including those typically referred to as "book outs" -- may only qualify as cash flow hedges if an entity can demonstrate that physical delivery or receipt of power occurred. The Company's forward electricity contracts continue to be exempt from fair value accounting requirements or to qualify as cash flow hedges, with the related gains and losses deferred in other comprehensive income. The implementation of Statement No. 149 did not have a material effect on the Company's financial statements.
In July 2003, the Emerging Issues Task Force (EITF) of the FASB issued EITF No. 03-11, which became effective on October 1, 2003. The standard addresses the reporting of realized gains and losses on derivative instruments and is being interpreted to require book outs to be recorded on a net basis in operating revenues. Adoption of this standard did not have a material impact on the Company's financial statements.
FASB Interpretation No. 46, Consolidation of Variable Interest Entities, which was originally issued in January 2003, requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. In December 2003, the FASB revised Interpretation No. 46 and deferred the effective date until March 31, 2004 for interests held in variable interest entities other than special purpose entities.
Current analysis indicates that the trusts established by the Company to issue preferred securities are variable interest entities under Interpretation No. 46, and that the Company is not the primary beneficiary of the trusts. If this conclusion is finalized, effective March 31, 2004, the trust assets and liabilities -- including the preferred securities issued by the trusts -- will be deconsolidated. The investments in the trusts and the loans from the trusts to the Company will be reflected as equity method investments and as long-term notes payable to affiliates, respectively, on the Balance Sheets. Based on December 31, 2003 values, this treatment would result in an increase of approximately $29 million to both total assets and liabilities. See Note 6 to the financial statements under "Mandatorily Redeemable Preferred Securities" for additional information.
In May 2003, the FASB issued Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity, which requires classification of certain financial instruments within its scope, including shares that are mandatorily redeemable, as liabilities. Statement No. 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise on July 1, 2003. In accordance with Statement No. 150,
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2003 Annual Report
the Company's mandatorily redeemable preferred securities are reflected as liabilities on the Balance Sheets. The adoption of Statement No. 150 had no impact on the Statements of Income and Cash Flows.
FINANCIAL CONDITION AND LIQUIDITY - ---------------------------------
Overview
Over the last several years, the Company's financial condition has remained stable with emphasis on cost control measures combined with significantly lower cost of capital, achieved through the refinancing and/or redemption of higher-cost long-term debt, preferred stock and preferred securities. The Company operated at high levels of reliability while achieving industry-leading customer satisfaction levels and continuing to have retail prices below the national average.
In 2003, gross utility plant additions were $743 million. These additions were primarily related to transmission and distribution facilities and the purchase of nuclear fuel and equipment to comply with environmental standards. The majority of funds needed for gross property additions for the last several years have been provided from operating activities. The Statements of Cash Flows provide additional details.
The Company's ratio of common equity to total capitalization -- including short-term debt -- was 48.3 percent in 2003, 48.3 percent in 2002, and 47.7 percent in 2001. See Note 6 to the financial statements for additional information.
Sources of Capital
The Company expects to meet future capital requirements primarily using funds generated from operating activities and equity funds from Southern Company and by the issuance of new debt securities, term loans, and short-term borrowings. The Company had $137 million of GPSC approved financing authority as of December 31, 2003. The Company used this remaining authority in February 2004. The type and timing of future financings will depend on market conditions and regulatory approval of additional financing authority. Recently, the Company has relied on the issuance of unsecured debt and preferred securities, in addition to unsecured pollution control bonds issued for its benefit by public authorities, to meet its long-term external financing requirements.
In February 2002, the Company defeased its first mortgage bond indenture and all related liens or encumbrances on the Company's property were discharged. As a result, the Company cannot issue any securities pursuant to this indenture. See "First Mortgage Bond Indenture" under Note 6 to the financial statements for additional information.
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. In accordance with the Public Utility Holding Company Act, most loans between affiliated companies must be approved in advance by the Securities and Exchange Commission (SEC).
The 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 which can fluctuate significantly due to the seasonality of the business.
To meet short-term cash needs and contingencies, the Company had approximately $725 million of unused credit arrangements with banks at the beginning of 2004. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other Southern Company 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. At December 31, 2003, the Company had outstanding $137 million of commercial paper and no extendible commercial notes.
At the beginning of 2004, the Company had not used any of its available credit arrangements. Bank credit arrangements are as follows:
Expires -------------------------------- Total Unused 2004 -------------------------------------------------------- (in millions) $725 $725 $725 ----------------------------------------------------------
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2003 Annual Report
All of these credit arrangements allow for the execution of term loans for an additional two year period.
Financing Activities
In 2003, the Company's financing costs increased due to the issuance of new debt during the year. New issues during 2001 through 2003 totaled $3.2 billion and retirement or repayment of higher-cost securities totaled $2.4 billion.
Composite financing rates for long-term debt, preferred stock, and preferred securities for the years 2001 through 2003, as of year-end, were as follows:
2003 2002 2001 --------------------------------- Composite interest rate on long-term debt 4.01% 4.47% 4.26% Composite preferred stock dividend rate 4.60 4.60 4.60 Composite preferred securities distribution 6.35 6.35 7.49 rate - ----------------------------------------------------------------
Subsequent to December 31, 2003, the Company has issued $550 million of new securities with the proceeds used primarily to retire higher coupon long-term debt and for construction and general corporate purposes.
Credit Rating Risk
The Company does not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are contracts that could require collateral -- but not accelerated payment -- in the event of a credit rating change to below investment grade. These contracts are primarily for physical electricity purchases and sales, fixed-price physical gas purchases, and agreements covering interest rate swaps. At December 31, 2003, the maximum potential collateral requirements were approximately $227 million. At December 31, 2003, there were no material collateral requirements for the gas purchase contracts or other financial instrument agreements.
Market Price Risk
Due to cost-based 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 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.
To mitigate the Company's exposure to interest rates, the Company has entered into interest rate swaps that were designed as cash flow hedges of variable rate debt or anticipated debt issuances. At December 31, 2003 the Company had no variable long-term debt outstanding that had not been hedged. Therefore, there would be no effect on annualized interest expense if the Company sustained a 100 basis point change in interest rates for all variable rate long-term debt. The Company is not aware of any facts or circumstances that would significantly affect such exposures in 2004. 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 and, to a lesser extent, into similar contracts for gas purchases. Fair value of changes in derivative energy contracts and year-end valuations were as follows:
Changes in Fair Value - ------------------------------------------------------------------ 2003 2002 - ------------------------------------------------------------------ (in millions) Contracts beginning of year $0.1 $0.4 Contracts realized or settled (0.4) 0.9 New contracts at inception - - Changes in valuation techniques - - Current period changes 3.5 (1.2) - ------------------------------------------------------------------ Contracts end of year $3.2 $0.1 ==================================================================
Source of 2003 Year-End Valuation Prices - ------------------------------------------------------------------ Maturity Total -------------------------- Fair Value Year 1 1-3 Years - ------------------------------------------------------------------ (in millions) Actively quoted $3.2 $2.8 $0.4 External sources - - - Models and other methods - - - - ------------------------------------------------------------------ Contracts end of year $3.2 $2.8 $0.4 ==================================================================
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2003 Annual Report
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. Gains and losses on derivative contracts that are not designated as hedges are recognized in the income statement as incurred. At December 31, 2003, the fair value of derivative energy contracts reflected in the financial statements was as follows:
Amounts ---------------------------------------------------------- (in millions) Regulatory liabilities, net $3.2 Other comprehensive income - Net income - ---------------------------------------------------------- Total fair value $3.2 ==========================================================
Gains (losses) recognized in income in 2003, 2002, and 2001 were not material. 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 $747 million for 2004, $812 million for 2005, and $1,043 million for 2006. Environmental expenditures included in these amounts are $91 million, $113 million, and $316 million for 2004, 2005, and 2006, respectively. Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
The Company has no generating plants under construction. However, construction related to new transmission and distribution facilities and capital improvements to existing generation, transmission and distribution facilities, including those needed to meet the environmental standards previously discussed, are ongoing.
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." Also as discussed in Note 1 to the financial statements under "Revenues and Fuel Costs," in 1993 the DOE implemented a special assessment over a 15-year period on utilities with nuclear plants to be used for the decontamination and decommissioning of its nuclear fuel enrichment facilities.
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 GPSC and the FERC.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2003 Annual Report
Other funding requirements related to obligations associated with scheduled maturities of long-term debt and preferred securities, as well as the related interest and distributions, preferred 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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Cautionary Statement Regarding Forward-Looking Information
The Company's 2003 Annual Report includes forward-looking statements in addition to historical information. Forward-looking information includes, among other things, statements concerning the estimated construction and other expenditures and the Company's projections for energy sales and its goals for future generating capacity and earnings growth. 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 comparable terminology. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include: o 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 and also changes in environmental, tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations; o current and future litigation, regulatory investigations, proceedings or inquiries, including the pending EPA civil action against the Company; o the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates; o the impact of fluctuations in commodity prices, interest rates, and customer demand; o available sources and costs of fuels; o ability to control costs; o investment performance of the Company's employee benefit plans; o advances in technology; o state and federal rate regulations and pending and future rate cases and negotiations; o effects of and changes in political, legal, and economic conditions and developments in the United States, including the current soft economy; o internal restructuring or other restructuring options that may be pursued; o potential business strategies, including acquisitions or dispositions of assets, which cannot be assured to be completed or beneficial to the Company; o the ability of counterparties of the Company to make payments as and when due; o the ability to obtain new short- and long-term contracts with neighboring utilities; o the direct or indirect effects on the Company's business resulting from the terrorist incidents on September 11, 2001, or any similar incidents or responses to such incidents; o financial market conditions and the results of financing efforts, including the Company's credit ratings; o the ability of the Company to obtain additional generating capacity at competitive prices; o weather and other natural phenomena; o the direct or indirect effects on the Company's business resulting from the August 2003 power outage in the Northeast, or any similar incidents; o the effect of accounting pronouncements issued periodically by standard-setting bodies; and o other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed from time to time by the Company with the SEC.
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NOTES TO FINANCIAL STATEMENTS GEORGIA POWER COMPANY 2003 ANNUAL REPORT
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
The Company is a wholly owned subsidiary of Southern Company, which is the parent company of five retail operating companies, Southern Power Company (Southern Power), Southern Company Services (SCS), Southern Communications Services (Southern LINC), Southern Company Gas (Southern Company GAS), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The retail operating companies -- Alabama Power, the Company, Gulf Power, Mississippi Power, and Savannah Electric -- 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, owns, and manages Southern Company's competitive generation assets and sells electricity at market-based rates in the wholesale market. Contracts among the retail operating companies and Southern Power -- related to jointly owned generating facilities, interconnecting transmission lines, or the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission (SEC). SCS, the system service company, provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern Company GAS is a competitive retail natural gas marketer serving customers in Georgia. Southern Holdings is an intermediate holding subsidiary for Southern Company's investments in synthetic fuels and leveraged leases and an energy services business. Southern Nuclear operates and provides services to Southern Company's nuclear power plants.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The Company is also subject to regulation by the FERC and the Georgia Public Service Commission (GPSC). 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 these estimates.
Certain prior years' data presented in the financial statements have been reclassified to conform with current year presentation.
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 $303 million in 2003, $318 million in 2002, and $286 million in 2001. Cost allocation methodologies used by SCS are approved by the SEC and management believes they are reasonable.
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, and systems and procedures services; strategic planning and budgeting services; and other services with respect to business and operations. Costs for these services amounted to $289 million in 2003, $301 million in 2002, and $281 million in 2001.
The Company has an agreement with Southern Power under which the Company operates and maintains Southern Power owned plants Dahlberg, Franklin, and Wansley at cost. Reimbursements under these agreements with Southern Power amounted to $5.3 million in 2003, $5.3 million in 2002 and $1.0 million in 2001. These agreements arose from the transfer of certain generation facilities to Southern Power in 2001 and 2002. See Note 7 under "Construction Program" for additional information.
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NOTES (continued) Georgia Power Company 2003 Annual Report
Southern Company holds a 30 percent ownership in Alabama Fuel Products, LLC (AFP), which produces synthetic fuel. The Company has an agreement with an indirect subsidiary of Southern Company that provides services for AFP. Under this agreement, the Company provides certain accounting functions, including processing and paying fuel transportation invoices, and the Company is reimbursed for its expenses. Amounts billed under this agreement totaled approximately $38 million in 2003. In addition, the Company purchases synthetic fuel from AFP for use at Plant Branch. Fuel purchases totaled $91 million in 2003.
Effective June 2002, the Company entered into purchased power agreements (PPAs) with Southern Power for capacity and energy. Purchased power costs in 2003 and 2002 amounted to $203 million and $128 million, respectively. Additionally, the Company recorded $7 million and $12 million of prepaid capacity expenses included in Other Deferred Charges and Other Assets on the Balance Sheets at December 31, 2003 and 2002, respectively. See Note 7 under "Fuel and 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 $5.6 million in 2003 and $4.5 million in 2002. The Company has an agreement with Savannah Electric under which the Company jointly owns a portion of Plant McIntosh. Under this agreement, Savannah Electric operates Plant McIntosh and the Company reimburses Savannah Electric for its proportionate share of the related expenses which were $3.6 million in 2003 and $1.8 million in 2002. See Note 4 for additional information.
Also see Note 4 for information regarding the Company's ownership in and purchased power agreement with Southern Electric Generating Company.
The retail operating companies, including the Company, Southern Power, and Southern Company GAS may jointly enter into various types of wholesale energy, natural gas and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Commitments" for additional information.
Revenues and Fuel Costs
Energy and other revenues are recognized as services are provided. Unbilled revenues are accrued at the end of each fiscal period. Fuel costs are expensed as the fuel is used. 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 recoverable fuel costs and amounts actually recovered in current rates.
The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts averaged less than 1 percent of revenues despite an increase in customer bankruptcies.
Fuel expense includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted to $74 million in 2003, $71 million in 2002, and $75 million in 2001. The Company has contracts with 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 January 1998 as required by the contracts, and the Company is pursuing legal remedies against the government for breach of contract. Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into the year 2015. At Plant Hatch, an on-site dry storage facility became operational in 2000 and can be expanded to accommodate spent fuel through the life of the plant. Construction of an on-site dry storage facility at Plant Vogtle will begin in sufficient time to maintain pool full-core discharge capability.
Also, the Energy Policy Act of 1992 required the establishment of a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants. The assessment is being paid over a 15-year period, which began in 1993. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment
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NOTES (continued) Georgia Power Company 2003 Annual Report
facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. The Company -- based on its ownership interest -- estimates its remaining liability at December 31, 2003 under this law to be approximately $10 million.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. See Note 3 under "Retail Rate Orders" for additional information regarding the disposition of the regulatory liability for the accelerated cost recovery recorded under the retail rate order that ended December 31, 2001. Regulatory assets and (liabilities) reflected in the Company's Balance Sheets at December 31 relate to the following:
2003 2002 Note ---------------------------- (in millions) Deferred income tax charges $ 510 $ 525 (a) Loss on reacquired debt 178 179 (b) Corporate building lease 54 54 (f) Vacation pay 50 54 (d) Postretirement benefits 23 25 (f) DOE assessments 13 16 (c) Generating plant outage costs 49 48 (f) Other regulatory assets 1 7 (f) Asset retirement obligation (16) - (a) Other cost of removal obligations (412) (800) (a) Accelerated cost recovery (111) (222) (e) Deferred income tax credits (187) (208) (a) Environmental remediation reserve (21) (21) (f) Purchased power (77) (63) (f) Other regulatory liabilities (3) (1) (f) - ------------------------------------------------------------------ Total $ 51 $ (26) ================================================================== 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 taxes 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 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) Assessments for the decontamination and decommissioning of the DOE's nuclear fuel enrichment facilities are recorded annually from 1993 through 2008. (d) Recorded as earned by employees and recovered as paid, generally within one year. (e) Amortized over a three-year period ending in 2004. See Note 3 under "Retail Rate Orders". (f) Recorded and recovered or amortized as approved by the GPSC.
In the event that a portion of the Company's operations is no longer subject to the provisions of Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and if impaired, write down the assets to their fair value. All regulatory assets and liabilities are to be reflected in rates.
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NOTES (continued) Georgia Power Company 2003 Annual Report
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 2.7 percent in 2003, 2.9 percent in 2002 and 3.3 percent in 2001. The composite depreciation rate was reduced because the lives of depreciable assets were extended effective January 2002 under the retail rate order. 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.
The Company recorded accelerated depreciation and amortization amounting to $91 million in 2001. Effective January 2002, the Company discontinued recording accelerated depreciation and amortization in accordance with a new retail rate order. Also, the Company was ordered to amortize $333 million -- the cumulative balance previously expensed -- equally over three years as a credit to amortization expense beginning January 2002. Additionally, effective January 2002 the Company was ordered to recognize new GPSC certified purchased power costs in rates evenly over the three years covered by the current retail rate order. As a result of the purchased power regulatory adjustment, the Company recorded amortization expenses of $14 million and $63 million in 2003 and 2002, respectively. The Company will record a credit to amortization expense of $77 million in 2004. See Note 3 under "Retail Rate Orders" for additional information.
Asset Retirement Obligations and Other Costs of Removal
In accordance with regulatory requirements, prior to January 2003, the Company followed the industry practice of accruing for the ultimate cost of retiring most long-lived assets over the life of the related asset as part of the annual depreciation expense provision. In accordance with SEC requirements such amounts are reflected on the Balance Sheet as regulatory liabilities. Effective January 1, 2003, the Company adopted FASB Statement No. 143, Accounting for Asset Retirement Obligations. Statement No. 143 established new accounting and reporting standards for legal obligations associated with the ultimate cost of retiring long-lived assets. The present value of the ultimate costs for an asset's future retirement must be recorded in the period in which the liability is incurred. The costs must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Additionally, Statement No. 143 does not permit the continued accrual of future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. However, the Company has received guidance regarding accounting for the financial statement impacts of Statement No. 143 from the GPSC and will continue to recognize the accumulated removal costs for other obligations as a regulatory liability. Therefore, the Company had no cumulative effect to net income resulting from the adoption of Statement No. 143.
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, 2003 was $423 million. In addition, the Company has retirement obligations related to various landfill sites, ash ponds, and underground storage tanks. The Company has also 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, a liability for the removal of these facilities will not be recorded because no reasonable estimate can be made regarding the timing of any related retirements. The Company will continue to recognize in the Statements of Income the ultimate removal costs in accordance with its regulatory treatment. Any difference between costs recognized under Statement No. 143 and those reflected in rates will be recognized as either a regulatory asset or liability in the Balance Sheets. The Company also revised the estimated cost to retire plants Hatch and Vogtle as a result of a new site-specific decommissioning study. The effect of the revision is a decrease of $24 million for the Statement No. 143 liability included in "Asset Retirement Obligations" with a corresponding decrease in property, plant and equipment. See "Nuclear Decommissioning" for further information on amounts included in rates.
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NOTES (continued) Georgia Power Company 2003 Annual Report
Details of the asset retirement obligations included in the Balance Sheets are as follows:
- -------------------------------------------------------- (in millions) Balance beginning of year $469 Liabilities incurred - Liabilities settled - Accretion 31 Cash flow revisions (24) - -------------------------------------------------------- Balance end of year $476 ========================================================
If Statement No. 143 had been adopted on January 1, 2002, the pro-forma asset retirement obligations would have been $440 million.
Nuclear Decommissioning
The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial nuclear power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. The Company has established external trust funds to comply with the NRC's regulations. The funds set aside for decommissioning are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC and the GPSC as well as the Internal Revenue Service (IRS). Funds are invested in a tax efficient manner in a diversified mix of equity and fixed income securities. Equity securities typically range from 50 to 75 percent of the funds and fixed income securities from 25 to 50 percent. Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the GPSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC 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 as of December 31, 2003 and the Company's ownership interests in plants Hatch and Vogtle were as follows:
Plant Plant Hatch Vogtle - ------------------------------------------------------------ Site study year 2003 2003 Decommissioning periods: Beginning year 2034 2027 Completion year 2065 2048 - ------------------------------------------------------------ (in millions) Site study costs: Radiated structures $497 $452 Non-radiated structures 49 58 - ------------------------------------------------------------ Total $546 $510 ============================================================
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 the estimates.
Annual provisions for nuclear decommissioning are based on an annuity method as approved by the GPSC. The amounts expensed in 2003 and fund balances were as follows:
Plant Plant Hatch Vogtle ------------------------------------------------------------ (in millions) Amount expensed in 2003 $ 7 $ 2 Accumulated provisions: External trust funds, at fair $269 $154 value Internal reserves 7 4 ------------------------------------------------------------ Total $276 $158 ============================================================
Effective January 1, 2002, the GPSC decreased the annual decommissioning costs for ratemaking to $9 million. This amount is based on the NRC generic estimate to decommission the radioactive portion of the facilities as of 2000. The estimates are $383 million and $282 million for plants Hatch and Vogtle, respectively. Significant assumptions used to determine the costs for ratemaking include an estimated inflation rate of 4.7 percent and an estimated trust earnings rate of 6.5 percent. The Company expects the GPSC to periodically
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review and adjust, if necessary, the amounts collected in rates for the anticipated cost of decommissioning.
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 site study decommissioning costs reflect the license extension; however, the updated costs will not be reflected in rates until the GPSC issues a new rate order, which is not expected until December 2004.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized
In accordance with regulatory treatment, the Company records AFUDC. AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. Interest related to the construction of new facilities not included in the Company's retail rates is capitalized in accordance with standard interest capitalization requirements. All current construction costs should be included in retail rates. For the years 2003, 2002, and 2001, the average AFUDC rates were 5.51 percent, 3.79 percent, and 6.33 percent, respectively. AFUDC and interest capitalized, net of taxes, was less than 3.0 percent of net income after dividends on preferred stock for 2003, 2002, and 2001.
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 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. In accordance with a GPSC order, the Company defers and amortizes nuclear refueling costs over the unit's operating cycle before the next refueling. The refueling cycles range from 18 to 24 months for each unit. In accordance with the 2001 retail rate 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.
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 that exceeds 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.
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.
Stock Options
Southern Company provides non-qualified stock options to a large segment of the Company's employees ranging from line management to executives. The Company accounts for its stock-based compensation plans in accordance with Accounting Principles Board Opinion No. 25. Accordingly, no compensation expense has been
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recognized because the exercise price of all options granted equaled the fair market value on the date of grant. When options are exercised, the Company receives a capital contribution from Southern Company equivalent to the related income tax benefit.
Financial Instruments
The Company uses derivative financial instruments to limit exposures 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.
The Company and its affiliates, through SCS acting as their agent, enter into commodity related forward and option contracts to limit exposure to changing prices on certain fuel purchases and electricity purchases and sales. 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 or regulatory assets or liabilities as appropriate 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:
Carrying Fair Amount Value -------------------------- Long-term debt: (in millions) At December 31, 2003 $3,685 $3,739 At December 31, 2002 $3,350 $3,417 Preferred securities: At December 31, 2003 $940 $976 At December 31, 2002 $940 $961 - -------------------------------------------------------------
The fair values for securities 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 values of marketable securities and qualifying cash flow hedges, and changes in additional minimum pension liabilities, net of income taxes less reclassifications for amounts included in net income.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed pension plan covering substantially all employees. The plan is funded in accordance with Employee Retirement Income Security Act (ERISA) requirements. No contributions to the plan are expected for the year ending December 31, 2004. The Company also provides certain non-qualified benefit plans for a selected group of management and highly compensated employees. Benefits under these non-qualified plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees. The Company funds related trusts to the extent required by the GPSC and the FERC. For the year ended December 31, 2004, such contributions are expected to total approximately $8.9 million.
The measurement date for plan assets and obligations is September 30 for each year. In 2002, the Company adopted several plan changes that had the effect of increasing benefits to both current and future retirees.
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Pension Plans
The accumulated benefit obligation for the pension plan was $1.6 billion and $1.4 billion for 2003 and 2002, respectively. Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows:
Projected Benefit Obligation ------------------------- 2003 2002 - -------------------------------------------------------------- (in millions) Balance at beginning of year $1,564 $1,448 Service cost 38 36 Interest cost 100 107 Benefits paid (83) (74) Amendments 6 33 Actuarial loss 102 14 - -------------------------------------------------------------- Balance at end of year $1,727 $1,564 ==============================================================
Plan Assets ------------------------- 2003 2002 - -------------------------------------------------------------- (in millions) Balance at beginning of year $1,838 $2,044 Actual return on plan assets 294 (137) Benefits paid (77) (69) - -------------------------------------------------------------- Balance at end of year $2,055 $1,838 ==============================================================
Pension plan assets are managed and invested in accordance with all applicable requirements including ERISA and the IRS revenue code. The Company's investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.
Plan Assets ------------------------------ Target 2003 2002 - ------------------------------------------------------------- Domestic equity 37% 37% 35% International equity 20 20 18 Global fixed income 26 24 25 Real estate 10 11 12 Private equity 7 8 10 - ------------------------------------------------------------- Total 100% 100% 100% =============================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
2003 2002 - --------------------------------------------------------------- (in millions) Funded status $328 $274 Unrecognized transition amount (13) (17) Unrecognized prior service cost 118 123 Unrecognized net actuarial gain (loss) (66) (78) - --------------------------------------------------------------- Prepaid pension asset, net 367 302 Portion included in employee benefit obligations 38 40 - --------------------------------------------------------------- Total prepaid pension recognized in the Balance Sheets $405 $342 ===============================================================
In 2003 and 2002, amounts recognized in the Balance Sheets for accumulated other comprehensive income and intangible assets to record the minimum pension liability related to the nonqualified plans were $26 million and $15 million and $13 and $10 million, respectively.
Components of the plans' net periodic cost were as follows:
2003 2002 2001 - --------------------------------------------------------------- (in millions) Service cost $ 38 $ 36 $ 35 Interest cost 100 107 101 Expected return on plan assets (179) (179) (168) Recognized net gain (19) (27) (31) Net amortization 6 4 3 - --------------------------------------------------------------- Net pension (income) $ (54) $ (59) $ (60) ===============================================================
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Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:
Accumulated Benefit Obligation ------------------------- 2003 2002 - -------------------------------------------------- ----------- (in millions) Balance at beginning of year $627 $542 Service cost 9 8 Interest cost 40 40 Benefits paid (29) (27) Actuarial loss 76 64 - -------------------------------------------------------------- Balance at end of year $723 $627 ==============================================================
Plan Assets ------------------------- 2003 2002 - -------------------------------------------------------------- (in millions) Balance at beginning of year $199 $195 Actual return on plan assets 36 (18) Employer contributions 59 49 Benefits paid (29) (27) - -------------------------------------------------------------- Balance at end of year $265 $199 ==============================================================
Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the IRS revenue code. The Company's investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company minimizes the risk of large losses through the primary tool of diversification but also monitors and manages other aspects of risk.
Plan Assets -------------------------------- Target 2003 2002 - ---------------------------------------------------------------- Domestic equity 43% 42% 38% International equity 20 21 21 Global fixed income 33 32 35 Real estate 2 3 3 Private equity 2 2 3 - ---------------------------------------------------------------- Total 100% 100% 100% ================================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows:
2003 2002 - -------------------------------------------------------------- (in millions) Funded status $(458) $(427) Unrecognized transition obligation 87 96 Unrecognized prior service cost 91 98 Unrecognized net loss 171 106 Fourth quarter contributions 9 37 - ---------------------------------------------------- --------- Employee benefit obligations recognized in the Balance Sheets $(100) $(90) ==============================================================
Components of the plans' net periodic cost were as follows:
2003 2002 2001 - -------------------------------------------------------------- (in millions) Service cost $ 9 $ 8 $ 9 Interest cost 40 40 39 Expected return on plan assets (24) (20) (19) Net amortization 16 15 14 - -------------------------------------------------------------- Net postretirement cost $ 41 $ 43 $ 43 ==============================================================
The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations and net periodic costs for the pension and postretirement benefit plans were:
2003 2002 2001 - --------------------------------------------------------------- Discount 6.0% 6.5% 7.5% Annual salary increase 3.8 4.0 5.0 Long-term return on plan assets 8.5 8.5 8.5 - ---------------------------------------------------------------
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 accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 8.25 percent for 2003, decreasing gradually to 5.25 percent through the year 2010 and remaining at that level thereafter. An annual increase or decrease in the
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assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2003 as follows:
1 Percent 1 Percent Increase Decrease - --------------------------------------------------------------- (in millions) Benefit obligation $70 $61 Service and interest costs 5 4 ===============================================================
Employee Savings Plan
The Company sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee's base salary. Total matching contributions made to the plan for the years 2003, 2002, and 2001 were $18 million, $17 million, and $16 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, and citizen enforcement of environmental requirements, 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 litigation against the Company cannot be predicted at this time; however, 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.
Retail Rate Orders
In December 2001, the GPSC approved a three-year retail rate order for the Company ending December 31, 2004. Retail rates were decreased by $118 million effective January 1, 2002. Under the terms of the order, earnings are evaluated against a retail return on common equity range of 10 percent to 12.95 percent. Two-thirds of any earnings above the 12.95 percent return are applied to rate refunds, with the remaining one-third retained by the Company. The Company's earnings in 2003 and 2002 were within the common equity range.
Under a previous three-year order ending December 2001, the Company's earnings were evaluated against a retail return on common equity range of 10 percent to 12.5 percent. The order further provided for $85 million in each year, plus up to $50 million of any earnings above the 12.5 percent return during the second and third years, to be applied to accelerated amortization or depreciation of assets. Two-thirds of any additional earnings above the 12.5 percent return were applied to rate refunds, with the remaining one-third retained by the Company. Pursuant to the order, the Company recorded $333 million of accelerated amortization and interest thereon, which has been credited to a regulatory liability account as mandated by the GPSC.
Under the 2001 rate order, the Company discontinued recording accelerated depreciation and amortization and began amortizing the accumulated balance equally over three years as a credit to expense beginning in 2002. Also, the rate order required the Company to recognize capacity and operating and maintenance costs related to new GPSC certified purchased power contracts evenly in rates over a three -year period ending December 31, 2004.
The Company is required to file a general rate case on July 1, 2004, in response to which the GPSC would be expected to determine whether the rate order should be continued, modified, or discontinued.
Under GPSC ratemaking provisions, $21 million has been deferred in a regulatory liability account for use in meeting future environmental remediation costs.
Retail Fuel Hedging Program
On December 24, 2002, the GPSC approved an order, effective in January 2003, allowing the Company to implement a natural gas and oil procurement and hedging program. This order allows the Company to use financial instruments to hedge price and commodity risk associated with these fuels. The order limits the program 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
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hedging program will be shared with the retail customers receiving 75 percent and the Company retaining 25 percent of the net gains.
Fuel Cost Recovery
In May 2003, the Company filed for a fuel cost recovery rate increase. On August 19, 2003, the GPSC issued an order approving a stipulation reached by the Company, the Consumers' Utility Counsel Division, Georgia Textile Manufacturers Association, Georgia Industrial Group and the staff of the GPSC. The stipulation allows the Company to increase fuel rates to recover existing under-recovered deferred fuel costs over the period of October 1, 2003 through March 31, 2005, as well as future projected fuel costs. The new fuel rate represents an average annual increase in rates paid by customers of approximately 1.6 percent.
Nuclear Performance Standards
The GPSC has adopted a nuclear performance standard for the Company's nuclear generating units under which the performance of plants Hatch and Vogtle is evaluated every three years. The performance standard is based on each unit's capacity factor as compared to the average of all comparable U.S. nuclear units operating at a capacity factor of 50 percent or higher during the three-year period of evaluation. Depending on the performance of the units, the Company could receive a monetary award or penalty under the performance standards criteria.
For the period 1999-2001, the Company's performance fell within the criteria prescribed by the GPSC. The Company will therefore not receive an award or penalty for the 1999-2001 performance periods.
Open Access Transmission Tariff
In October 2003, the FERC approved a new Open Access Transmission Tariff for the Company of $1.73 per kilowatt-month based on an 11.25 percent return on equity. The Company had requested a rate increase effective January 2002 based on a 13 percent return on equity. Pending FERC approval, the Company collected from customers based on the 13 percent return on equity, but recorded revenue subject to refund for amounts above the previously approved rate of $1.37 per kilowatt-month. As a result of the final settlement, a total of approximately $2.3 million was refunded to the Company's transmission customers in October 2003 and $7.2 million was recorded as revenue.
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action against the Company alleging the Company had violated the New Source Review (NSR) provisions of the Clean Air Act with respect to coal-fired generating facilities at the Company's Bowen and Scherer plants and violations of related state laws. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued to the Company a notice of violation related to the two plants mentioned previously. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation.
The action against the Company was stayed in the spring of 2001 during the appeal of a very similar NSR enforcement action against the Tennessee Valley Authority (TVA) before the U.S. Court of Appeals for the Eleventh Circuit. The TVA appeal involves many of the same legal issues raised by the actions against the Company. Because the final resolution of the TVA appeal could have a significant impact on the Company, the Company has been involved in that appeal. On June 24, 2003, the court of appeals issued its ruling in the TVA case. It found unconstitutional the statutory scheme set forth in the Clean Air Act that allowed the EPA to impose penalties for failing to comply with an administrative compliance order, like the one issued to TVA, without the EPA having to prove the underlying violation. Thus, the court of appeals held that the compliance order was of no legal consequence, and TVA was free to ignore it. The court did not, however, rule directly on the substantive legal issues about the proper interpretation and application of certain NSR provisions that had been raised in the TVA appeal. On September 16, 2003, the court of appeals denied the EPA's request for a rehearing of the decision and on February 13, 2004, the EPA petitioned the U.S. Supreme Court to review the Eleventh Circuit's decision. At this time, no party to the Company's action, which was administratively closed two years ago, has asked the court to reopen that case.
Since the inception of the NSR proceedings against the Company, the EPA has also been proceeding with similar NSR enforcement actions against other
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utilities, involving many of the same legal issues. In each case, the EPA alleged that the utilities failed to comply with the NSR permitting requirements when performing maintenance and construction activities at coal-burning plants, which activities the Company considers to be routine or otherwise not subject to NSR. In 2003, district courts addressing these cases issued opinions that reached conflicting conclusions.
In October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act clarifying the scope of the existing Routine Maintenance, Repair, and Replacement exclusion. On December 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit stayed the effectiveness of these revisions pending resolution of related litigation. In January 2004, the Bush Administration announced that it would continue to enforce the existing rules.
The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome in this case could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
Plant Wansley Environmental Litigation
On December 30, 2002, the Sierra Club, Physicians for Social Responsibility, Georgia ForestWatch, and one individual filed a civil suit in the U.S. District Court in Georgia against the Company for alleged violations of the Clean Air Act at four of the generating units at Plant Wansley. The complaint alleges Clean Air Act violations at both the existing coal-fired units and the new combined cycle units. Specifically, the plaintiffs allege (1) opacity violations at the coal-fired units, (2) violations of a permit provision that requires the combined cycle units to operate above certain levels, (3) violation of the nitrogen oxide emission offset requirements, and (4) violation of the hazardous air pollutant requirements. The civil action requests injunctive and declaratory relief, civil penalties, a supplemental environmental project, and attorneys' fees. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit.
On June 19, 2003, the court granted the Company motion to dismiss the allegations regarding hazardous air pollutants and denied the Company's motion to dismiss the allegations regarding emission offsets. On August 29, 2003, the Company filed a motion for partial summary judgment regarding emission offsets. On January 20, 2004, the Company filed a motion for summary judgment on the remaining three counts, and the plaintiffs have filed motions for partial summary judgment. The case is currently scheduled for trial during the summer of 2004. While the Company believes that it has complied with applicable laws and regulations, an adverse outcome could require payment of substantial penalties. The final outcome of this matter cannot now be determined.
Potentially Responsible Party Status
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. The Company has recognized $34 million in cumulative expenses through December 31, 2003 for the assessment and anticipated cleanup of sites on the Georgia Hazardous Sites Inventory. In addition, in 1995 the EPA designated the Company and four other unrelated entities as potentially responsible parties at a site in Brunswick, Georgia that is listed on the federal National Priorities List. The Company has contributed to the removal and remedial investigation and feasibility study costs for the site. Additional claims for recovery of natural resource damages at the site are anticipated. As of December 31, 2003, the Company had recorded approximately $6 million in cumulative expenses associated with the Company's agreed-upon share of the removal and remedial investigation and feasibility study costs for the Brunswick site.
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 liability, if any, at these sites would be material to the financial statements.
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Race Discrimination Litigation
In July 2000, a lawsuit alleging race discrimination was filed by three Georgia Power employees against the Company, Southern Company, and SCS in the Superior Court of Fulton County, Georgia. Shortly, thereafter, the lawsuit was removed to the U.S. District Court for the Northern District of Georgia. The lawsuit also raised claims on behalf of a purported class. The plaintiffs seek compensatory and punitive damages in an unspecified amount, as well as injunctive relief. In August 2000, the lawsuit was amended to add four more plaintiffs. Also, Southern Company Energy Solutions, a subsidiary of Southern Company, was named a defendant.
In October 2001, the district court denied the plaintiffs' motion for class certification. The plaintiffs filed a motion to reconsider the order denying class certification, and the court denied the plaintiffs' motion to reconsider. In December 2001, the plaintiffs filed a petition in the U. S. Court of Appeals for the Eleventh Circuit seeking permission to file an appeal of the October 2001 decision, and this petition was denied. After discovery was completed on the claims raised by the seven named plaintiffs, the defendants filed motions for summary judgment on all of the named plantiffs' claims. On March 31, 2003, the U.S. District Court for the Northern District of Georgia granted summary judgment in favor of the defendants on all claims raised by all seven plaintiffs. On April 23, 2003 plaintiffs filed an appeal to the U.S. Court of Appeals for the Eleventh Circuit challenging these adverse summary judgment rulings, as well as the District Court's October 2001 ruling denying class certification. Oral arguments occurred January 27, 2004, and the parties await the court's decision. The final outcome of this matter cannot now be determined.
Right of Way Litigation
Southern Company and certain of its subsidiaries including the Company, Gulf Power, Mississippi Power, and Southern Telecom (collectively defendants) have been named as defendants in numerous lawsuits brought by landowners since 2001 regarding the installation and use of fiber optic cable over defendants' rights of way located on the landowners' property. 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 by defendants exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment. The plaintiffs seek compensatory and punitive damages and injunctive relief. Management believes that the Company has complied with applicable laws and the plaintiffs' claims are without merit. An adverse outcome in these matters could result in substantial judgments; however, the final outcome of these matters cannot now be determined.
In addition, in late 2001, certain subsidiaries of Southern Company, including Alabama Power, the Company, Gulf Power, Mississippi Power, Savannah Electric and Southern Telecom (collectively, defendants) 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 the telecommunications company in pending and future right of way litigation. The Company believes that the plaintiff's claims are without merit. 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.
FERC Matters
The Company has obtained FERC approval to sell power to non-affiliates at market-based prices under specific contracts. The Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities' applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company's retail operating companies, and found them to be "pivotal suppliers" in their control area market and ordered the implementation of certain mitigation measures. SCS, on behalf of the Company and the other retail operating companies, sought rehearing of the FERC order and the FERC delayed implementation of certain mitigation measures. SCS, on behalf of
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the Company and the other retail operating companies, submitted comments to the FERC in 2002 regarding these issues. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. The Company anticipates that the FERC will address the requests for rehearing in the near future. Regardless of the outcome of the SMA proposal, the FERC retains the ability to modify or withdraw the authorization for any seller to sell at market-based rates, if it determines that the underlying conditions for having such authority are no longer applicable. The final outcome of this matter will depend on the form in which the SMA test and mitigation measures rules may be ultimately adopted and cannot be determined at this time.
PPAs by the Company for Southern Power's Plant McIntosh capacity were certified by the GPSC in December 2002 after a competitive bidding process. In April 2003, Southern Power applied for FERC approval of these PPAs. Interveners have made filings in opposition of the FERC's acceptance of the PPAs, alleging that the PPAs do not meet the applicable standards for market-based rates between affiliates. In July 2003, the FERC accepted the PPAs to become effective June 1, 2005, subject to refund, and ordered that hearings be held to determine: (a) whether, in the design and implementation of the GPSC competitive bidding process, the Company unduly preferred Southern Power; (b) whether the analysis of the competitive bids unduly favored Southern Power, particularly with respect to evaluation of non-price factors; (c) whether the Company selected its affiliate, Southern Power, based upon a reasonable combination of price and non-price factors; (d) whether Southern Power received an undue preference or competitive advantage in the competitive bidding process as a result of access to its affiliate's transmission system; (e) whether and to what extent the PPAs impact wholesale competition; and (f) whether the PPAs are just and reasonable and not unduly discriminatory. Hearings are scheduled to begin in March 2004. Management believes that the PPAs should be approved by the FERC; however, the ultimate outcome of this matter cannot now be determined.
4. JOINT OWNERSHIP AGREEMENTS
The Company and an affiliate, Alabama Power, own equally all of the outstanding capital stock of Southern Electric Generating Company (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:
2003 2002 2001 ---------------------------------- (in millions) Energy $55 $53 $52 Capacity 34 32 30 - --------------------------------------------------------- Total $89 $85 $82 =========================================================
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 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 also jointly owns Plant McIntosh with Savannah Electric who operates the plant. The Company and Florida Power Corporation (FPC) jointly own a combustion turbine unit (Intercession City) operated by FPC.
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At December 31, 2003, the Company's percentage ownership and investment (exclusive of nuclear fuel) in jointly owned facilities in commercial operation were as follows:
Company Accumulated Facility (Type) Ownership Investment Depreciation - -------------------------------------------------------------------- (in millions) Plant Vogtle (nuclear) 45.7% $3,307 $1,706 Plant Hatch (nuclear) 50.1 908 469 Plant Wansley (coal) 53.5 390 160 Plant Scherer (coal) Units 1 and 2 8.4 115 52 Unit 3 75.0 560 247 Plant McIntosh Common Facilities 75.0 24 3 (combustion-turbine) Rocky Mountain 25.4 169 85 (pumped storage) Intercession City 33.3 12 1 (combustion-turbine) - --------------------------------------------------------------------
The Company has contracted to operate and maintain the jointly owned facilities as agent for their co-owners, except as noted above. 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 and its subsidiaries file a consolidated federal income tax return. As a result of new State of Georgia Department of Revenue regulations applicable to tax years beginning on or after January 1, 2002, Southern Company and its subsidiaries were granted permission by the State of Georgia Department of Revenue Commissioner to file a combined State of Georgia income tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. In accordance with both IRS and State of Georgia Department of Revenue regulations, each company is jointly and severally liable for the tax liability.
At December 31, 2003, tax-related regulatory assets were $510 million and tax-related regulatory liabilities were $187 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.
Details of the federal and state income tax provisions are as follows:
2003 2002 2001 ----------------------------- Total provision for income taxes: (in millions) Federal: Current $143 $261 $352 Deferred 181 60 (46) - --------------------------------------------------------------- 324 321 306 - --------------------------------------------------------------- State: Current 24 31 61 Deferred 16 5 (8) Deferred investment tax credits 2 - 5 - --------------------------------------------------------------- Total $366 $357 $364 ===============================================================
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:
2003 2002 ------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $1,966 $1,779 Property basis differences 563 623 Other 329 309 - ----------------------------------------------------------------- Total 2,858 2,711 - ----------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 96 90 Other property basis differences 156 170 Other deferred costs 160 214 Other 75 64 - ----------------------------------------------------------------- Total 487 538 - ----------------------------------------------------------------- Net deferred tax liabilities 2,371 2,173 Portion included in prepaid expenses - 3 - ----------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $2,371 $2,176 =================================================================
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 $15 million in 2003, $12 million in
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2002 and $15 million in 2001. At December 31, 2003, all investment tax credits available to reduce federal income taxes payable had been utilized.
A reconciliation of the federal statutory tax rate to the effective income tax rate is as follows:
2003 2002 2001 ------------------------------ Federal statutory rate 35% 35% 35% State income tax, net of federal deduction 3 2 4 Non-deductible book depreciation 1 1 2 Other (2) (1) (4) - -------------------------------------------------------------- Effective income tax rate 37% 37% 37% ==============================================================
6. CAPITALIZATION
Mandatorily Redeemable Preferred Securities
The Company has formed certain wholly-owned trust subsidiaries for the purpose of issuing preferred securities. The proceeds of the related equity investments and security sales were loaned back to the Company through the issuance of junior subordinated notes totaling $969 million, which constitute substantially all of the assets of the trusts. The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective trusts' payment obligations with respect to these preferred securities. At December 31, 2003, preferred securities of $940 million were outstanding and recognized as liabilities in the Balance Sheets.
Long-Term Debt Due Within One Year
A summary of the improvement fund requirements and scheduled maturities and redemptions of securities due within one year at December 31 is as follows:
2003 2002 ---------------------- (in millions) Capital lease $2 $ 2 Senior notes - 320 - ------------------------------------------------------------- Total $2 $322 =============================================================
Serial maturities through 2008 applicable to total long-term debt are as follows: $2 million in 2004; $453 million in 2005; $153 million in 2006; $303 million in 2007; and $3 million in 2008.
First Mortgage Bond Indenture
In 2002, the first mortgage bond indenture of the Company was defeased by paying to JPMorgan Chase Bank, the trustee, an amount representing the last outstanding obligations on the Company's first mortgage bonds. As a result of the defeasance, there are no longer any first mortgage bond liens on the Company's property and the Company no longer has to comply with the covenants and restrictions of the first mortgage bond indenture.
Pollution Control 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, 2003 was $1.7 billion.
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, 2003 and 2002, the Company had a capitalized lease obligation for its corporate headquarters building of $79 million and $81 million, respectively, with an interest rate of 8.1 percent. For ratemaking purposes, the GPSC 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 GPSC. At both December 31, 2003 and 2002, the interest and lease amortization deferred on the Balance Sheets was $54 million.
Bank Credit Arrangements
At the beginning of 2004, the Company had an unused credit arrangement with banks totaling $725 million expiring at June 11, 2004. Upon expiration, the $725 million agreement provides the option of converting borrowings into a two-year term loan. The agreement contains stated borrowing rates but also allows for competitive bid loans. In addition, the agreement requires 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
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NOTES (continued) Georgia Power Company 2003 Annual Report
percent for the Company. Compensating balances are not legally restricted from withdrawal. A fee is also paid to the agent bank.
The credit arrangements contain covenants that limit the level of indebtedness to capitalization to 65 percent, as defined in the agreement. Exceeding these limits would result in an event of default under the credit arrangement. 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. The Company is currently in compliance with all such covenants.
This $725 million in unused credit arrangements provides liquidity support to the Company's variable rate pollution control bonds. The amount of variable rate pollution control bonds outstanding requiring liquidity support as of December 31, 2003 was $106 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, 2003 was $137 million. There were no outstanding extendible commercial notes at December 31, 2003. The amount of commercial paper outstanding at December 31, 2002 was $358 million, which included $19 million of extendible commercial notes. During 2003, the peak amount of commercial paper outstanding was $531 million and the average amount outstanding was $229 million. The average annual interest rate on commercial paper in 2003 was 1.23 percent. Commercial paper is included in notes payable on the Balance Sheets.
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 GPSC. The Company also enters into hedges of forward electricity sales.
At December 31, 2003, the fair value of derivative energy contracts was reflected in the financial statements as follows:
Amounts ------------ (in millions) Regulatory liabilities, net $3.2 Other comprehensive income - Net income - - ------------------------------------------------------- Total fair value $3.2 =======================================================
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 are generally structured to mirror the critical terms of the hedged debt instruments; therefore, no material ineffectiveness has been recorded in earnings.
At December 31, 2003, the Company had interest rate swaps outstanding with net deferred losses as follows:
Cash Flow Hedges
Weighted Average Fixed Fair Rate Notional Value Maturity Paid Amount (Loss) - ---------------------------------------------------------- (in millions) 2004 1.39% $873 $(0.8) 2005 1.56 50 0 2005 1.96 250 (1.1)
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 2003, the Company recognized losses totaling $11.3 million upon termination of certain interest derivatives at the same time it issued debt. These losses have been deferred in other comprehensive income and will be amortized to interest expense over the life of the related debt. For 2003, approximately $3.4 million of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2004, pre-tax losses of approximately $3.2 million are expected to be reclassified from other comprehensive income to interest expense.
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NOTES (continued) Georgia Power Company 2003 Annual Report
7. COMMITMENTS
Construction Program
The Company currently estimates property additions to be approximately $747 million, $812 million, and $1,043 million in 2004, 2005, and 2006, respectively. These amounts include $28.9 million, $19.7 million and $20.0 million in 2004, 2005, and 2006, respectively, for construction expenditures related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included under "Fuel and Purchased Power 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 transmission 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, 2003, significant purchase commitments were outstanding in connection with the construction program.
The Company has no generating plants under construction. However, construction related to new transmission and distribution facilities and capital improvements to existing generation, transmission and distribution facilities, including those needed to meet the environmental standards previously discussed, are ongoing.
The Company had three generation projects under construction during 2001. They included two units at Plant Dahlberg, a ten-unit, 800 megawatt combustion turbine facility; two combined cycle units totaling 1,132 megawatts at Plant Wansley; and Plant Franklin, a two-unit, 1,181 megawatt combined cycle facility. All three of these projects have been transferred to Southern Power. The ten Dahlberg units and two Franklin units were transferred in 2001 and the transfer of the two Wansley units was completed in January 2002.
Southern Company has guaranteed Southern Power obligations totaling $10.7 million for the Company's construction of transmission interconnection facilities to these plants.
Fuel and Purchased Power Commitments
To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Natural gas purchase commitments contain 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 future prices at December 31, 2003. Also the Company has entered into various long-term commitments for the purchase of electricity. Total estimated minimum long-term obligations at December 31, 2003 were as follows:
Coal and Natural Nuclear Year Gas Fuel - ---- ------------------------- (in millions) 2004 $ 156 $1,321 2005 149 1,045 2006 148 895 2007 108 603 2008 172 372 2009 and thereafter 1,625 183 - ------------------------------------------------------- Total commitments $2,358 $4,419 =======================================================
Additional commitments for coal and for nuclear fuel will be required to supply the Company's future needs.
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company retail operating companies, Southern Power, and Southern Company GAS. Under these agreements, each of the retail operating companies, Southern Power, and Southern Company Gas may be jointly and severally liable. The creditworthiness of Southern Power and Southern Company GAS is currently inferior to the creditworthiness of the retail operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the retail operating companies to insure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power or Southern Company GAS as a contracting party under these agreements.
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NOTES (continued) Georgia Power Company 2003 Annual Report
The Company has commitments regarding a portion of a 5 percent 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. Except as noted below, the cost of such capacity and energy is included in purchased power from non-affiliates in the Company's Statements of Income. Capacity payments totaled $57 million, $57 million, and $59 million in 2003, 2002, and 2001, respectively. The current projected Plant Vogtle capacity payments are:
Year Capacity Payments - ---- ----------------- (in millions) 2004 $ 57 2005 56 2006 54 2007 54 2008 54 2009 and thereafter 369 - ------------------------------------------------------- Total $644 =======================================================
Portions of the payments noted above 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.
The Company has entered into other various long-term commitments for the purchase of electricity. Estimated total long-term obligations at December 31, 2003 were as follows:
Non- Year Affiliated Affiliated - ---- ---------- ---------- (in millions) 2004 $ 191 $ 45 2005 268 79 2006 283 88 2007 283 89 2008 282 90 2009 and thereafter 1,722 482 - ----------------------------------------------------------- Total $3,029 $873 ===========================================================
Operating Leases
The Company has entered into various operating leases with various terms and expiration dates. Rental expenses related to these operating leases totaled $36 million for 2003, $35 million for 2002, and $14 million for 2001. At December 31, 2003, estimated minimum rental commitments for these noncancelable operating leases were as follows:
------------------------------------ Minimum Obligations ------------------------------------ Year Rail Cars Other Total - ---- ----------------------------------- (in millions) 2004 $ 12 $22 $ 34 2005 12 18 30 2006 12 14 26 2007 10 12 22 2008 11 11 22 2009 and thereafter 56 16 72 - ------------------------------------------------------------- Total $113 $93 $206 =============================================================
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 2004 and 2010, and the Company's maximum obligations are $13 million and $40 million, respectively. 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. Rental expenses related to the rail car leases are fully recoverable through the fuel cost recovery clause as ordered by the GPSC.
Guarantees
Prior to 1999, a subsidiary of Southern Company originated loans to residential customers of the Company for heat pump purchases. These loans were sold to Fannie Mae with recourse for any loan with payments outstanding over 120 days. The Company is responsible for the repurchase of customers' delinquent loans. As of December 31, 2003, the outstanding loans guaranteed by the Company were $8.7 million and loan loss reserves of $1.8 million have been recorded.
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
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NOTES (continued) Georgia Power Company 2003 Annual Report
principal amount of pollution control revenue bonds are outstanding. The Company has agreed to reimburse Alabama Power for the pro rata portion of such obligation 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. In May 2003, SEGCO issued an additional $50 million in senior notes. Alabama Power guaranteed the debt obligation and in October 2003, the Company agreed to reimburse Alabama Power for the pro rata portion of such obligation corresponding to its 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. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988, 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 nuclear power plants. The Act provides funds up to $10.9 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 aggregate of $10 million per incident to be paid in a calendar year for each reactor. Such maximum assessment for the Company, excluding any applicable state premium taxes -- based on its ownership and buyback interests - -- is $203 million per incident but not more than an aggregate of $20 million to be paid for each incident in any one year. The Price-Anderson Amendments Act expired in August 2002; however, the indemnity provisions of the Act remain in place for commercial nuclear reactors.
The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members' nuclear generating facilities.
Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.
NEIL also covers 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 this deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. The Company purchases the maximum limit allowed by NEIL subject to ownership limitations and has elected a 12 week waiting period.
Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for the Company under the NEIL policies would be $40 million.
Following the terrorist attacks of September 2001, both ANI and NEIL confirmed that terrorist acts against commercial nuclear power stations would be covered under their insurance. Both companies, however, revised their policy terms on a prospective basis to include an industry aggregate for all "non-certified" terrorist acts (i.e., acts that are not certified acts of terrorism pursuant to the Terrorism Risk Insurance Act of 2002 (TRIA). The NEIL aggregate -- applies to non-certified claims stemming from terrorism within a 12-month duration -- is $3.24 billion plus any amounts available through reinsurance or indemnity from an outside source. The non-certified ANI cap is a $300 million shared industry aggregate. Any act of terrorism that is certified pursuant to the TRIA will not be subject to the foregoing NEIL and ANI limitations but will be subject to the TRIA annual aggregate limitation of $100 billion of insured losses arising from certified acts of terrorism. The TRIA will expire on December 31, 2005.
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
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NOTES (continued) Georgia Power Company 2003 Annual Report
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.
9. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for 2003 and 2002 is as follows:
Net Income After Dividends on Operating Operating Preferred Stock Quarter Ended Revenues Income - --------------------------------------------------------------------- (in millions) -------------------------------------------- March 2003 $1,126 $262 $133 June 2003 1,190 293 159 September 2003 1,487 490 265 December 2003 1,111 179 74
March 2002 $1,007 $260 $127 June 2002 1,204 320 171 September 2002 1,517 498 271 December 2002 1,095 126 49 - ---------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions.
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GULF POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Gulf Power Company 2003 Annual Report
The management of Gulf Power Company has prepared -- and is responsible for -- the financial statements and related information included in this report. These statements were prepared in accordance with accounting principles generally accepted in the United States and necessarily include amounts that are based on the best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that the accounting records reflect only authorized transactions of the Company. Limitations exist in any system of internal controls, however, based on a recognition that the cost of the system should not exceed its benefits. The Company believes its system of internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's internal accounting controls are evaluated on an ongoing basis by the Company's internal audit staff. The Company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements.
The audit committee of Southern Company's board of directors, composed of four independent directors, provides a broad overview of management's financial reporting and control functions. Additionally, the Company's Controls and Compliance Committee, comprised of five outside directors, meets periodically with management, the internal auditors, and the independent public accountants to discuss auditing, internal controls, and compliance matters. The internal auditors and independent public accountants have access to the members of these committees at any time.
Management believes that its policies and procedures provide reasonable assurance that the Company's operations are conducted according to a high standard of business ethics.
In management's opinion, the financial statements present fairly, in all material respects, the financial position, results of operations, and cash flows of Gulf Power Company in conformity with accounting principles generally accepted in the United States.
/s/Susan N. Story Susan N. Story President and Chief Executive Officer
/s/Ronnie R. Labrato Ronnie R. Labrato Vice President, Chief Financial Officer, and Comptroller March 1, 2004
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INDEPENDENT AUDITORS' REPORT Gulf Power Company 2003 Annual Report
Gulf Power Company:
We have audited the accompanying balance sheets and statements of capitalization of Gulf Power Company (a wholly owned subsidiary of Southern Company) as of December 31, 2003 and 2002, and the related statements of income, comprehensive income, common stockholder's equity, and cash flows for the years then ended. These financial statements are the responsibility of Gulf Power Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The financial statements of Gulf Power Company for the year ended December 31, 2001 were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements and included an explanatory paragraph that described a change in the method of accounting for derivative instruments and hedging activities in their report dated February 13, 2002.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, the financial statements (pages II-175 to II-195) present fairly, in all material respects, the financial position of Gulf Power Company at December 31, 2003 and 2002, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the financial statements, in 2003 Gulf Power Company changed its method of accounting for asset retirement obligations.
/s/Deloitte & Touche LLP Atlanta, Georgia March 1, 2004
THE FOLLOWING REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH THE COMPANY'S 2001 ANNUAL REPORT on Form 10-K and has not been reissued by Arthur Andersen LLP. See Exhibit 23(d)2 for additional information.
To Gulf Power Company:
We have audited the accompanying balance sheets and statements of capitalization of Gulf Power Company (a Maine corporation and a wholly owned subsidiary of Southern Company) as of December 31, 2001 and 2000, and the related statements of income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Com-pany's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the 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, the financial statements (pages II-129 to II-144) referred to above present fairly, in all material respects, the financial position of Gulf Power Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
As explained in Note 1 to the financial statements, effective January 1, 2001, Gulf Power Company changed its method of accounting for derivative instruments and hedging activities.
Atlanta, Georgia February 13, 2002
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Gulf Power Company 2003 Annual Report
OVERVIEW OF EARNINGS AND - ------------------------ BUSINESS ACTIVITIES - -------------------
Earnings
Gulf Power Company's 2003 net income after dividends on preferred stock was $69.0 million, an increase of $2.0 million from the previous year. In 2002, earnings were $67.0 million, an increase of $8.7 million from the previous year. In 2001, earnings were $58.3 million, up $6.5 million when compared to the prior year. The improvement in earnings in 2003 is due primarily to higher operating revenues related to an increase in base rates effective in May 2002, offset somewhat by higher operating expenses and increases in depreciation expense primarily related to the commercial operation of Plant Smith Unit 3 beginning in April 2002. The improvement in earnings in 2002 is due primarily to higher operating revenues related to the increase in base rates, offset somewhat by higher operating expenses and higher financing costs primarily related to the commercial operation of the new unit. The increase in 2001 earnings was primarily a result of an increase in Allowance for Funds Used During Construction (AFUDC) and lower interest expense during construction of the unit.
Business Activities
The Company operates as a vertically integrated utility providing electricity to 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 Public Service Commission (FPSC).
Several factors affect the opportunities, challenges, and risks of selling electricity. These factors include the Company's ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stricter environmental standards. 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.
RESULTS OF OPERATIONS - ---------------------
A condensed income statement follows: Increase (Decrease) Amount From Prior Year - ----------------------------------------------------------------- 2003 2003 2002 2001 - ----------------------------------------------------------------- (in millions) Operating revenues $878 $ 58 $ 95 $ 11 - ----------------------------------------------------------------- Fuel 317 42 73 (15) Purchased power 50 (12) (44) 24 Other operation and maintenance 211 11 23 5 Depreciation and amortization 82 5 9 1 Taxes other than income taxes 66 5 6 (1) - ----------------------------------------------------------------- Total operating expenses 726 51 67 14 - ----------------------------------------------------------------- Operating income 152 7 28 (3) Interest Expenses and other, net (42) (1) (13) 10 Income taxes (41) (4) (6) - - ----------------------------------------------------------------- Net income $ 69 $ 2 $ 9 $ 7 =================================================================
Revenues
Operating revenues increased in 2003 when compared to 2002 and 2001. The following table summarizes the changes in operating revenues for the past three years:
2003 2002 2001 --------------------------------------- (in thousands) Retail - Prior Year $665,836 $584,591 $548,640 Change in - Base Revenues 22,000 31,200 - Sales Growth 7,040 16,557 10,254 Weather (6,757) 9,497 (5,699) Fuel and other cost recovery 11,055 23,991 31,396 - -------------------------------------------------------------------- Retail--Current Year 699,174 665,836 584,591 - -------------------------------------------------------------------- Sales for resale-- Non-affiliates 76,767 77,171 82,252 Affiliates 63,268 40,391 27,256 - -------------------------------------------------------------------- Total sales for resale 140,035 117,562 109,508 Other operating revenues 38,488 37,069 31,104 - -------------------------------------------------------------------- Total operating revenues $877,697 $820,467 $725,203 ==================================================================== Percent change 7.0% 13.1% 1.5% - --------------------------------------------------------------------
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2003 Annual Report
Retail revenues increased $33.3 million, or 5.0 percent in 2003, $81.2 million, or 13.9 percent, in 2002, and $36.0 million, or 6.6 percent, in 2001. The significant factors driving these changes are shown in the table above. See Note 3 to the financial statements under "Retail Revenue Sharing Plan" for further information.
"Fuel and other cost recovery" includes: recovery provisions for fuel expenses and the energy component of purchased power costs, energy conservation costs, purchased power capacity costs, and environmental compliance costs. Annually, the Company seeks recovery of projected costs including any true-up amount from prior periods. Approved rates are implemented each January. Therefore, the recovery provisions generally equal the related expenses and have no material effect on net income. See Notes 1 and 3 to the financial statements under "Revenues and Regulatory Cost Recovery Clauses" and "Environmental Cost Recovery," respectively, for further information.
Sales for resale were $140.0 million in 2003, an increase of $22.5 million, or 19.1 percent, primarily due to increased energy sales for resale to affiliates reflecting greater availability of generation when compared to 2002. Sales for resale were $117.6 million in 2002, an increase of $8.1 million, or 7.4 percent, due to increased energy sales for resale to affiliates reflecting the commercial operation of Plant Smith Unit 3. Sales for resale were $109.5 million in 2001, a decrease of $24.4 million, or 18.2 percent, from 2000. These changes were primarily weather related. Sales to affiliated companies vary from year to year depending on demand and the availability and cost of generating resources at each company. These energy sales do not have a significant impact on earnings, since they are generally sold at marginal cost.
Revenues from sales to utilities outside the service area under long-term contracts consist of capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. The capacity and energy components under these long-term contracts were as follows:
2003 2002 2001 ----------------------------------- (in thousands) Unit Power -- Capacity $18,598 $19,898 $19,472 Energy 30,894 28,565 27,579 - ------------------------------------------------------------- Total $49,492 $48,463 $47,051 =============================================================
Capacity revenues remained relatively unchanged during 2003, 2002, and 2001. Unit power from specific generating plants is currently being sold to Progress Energy FL, Florida Power & Light Company, and Jacksonville Electric Authority. Under these agreements, 211 megawatts of net dependable capacity were sold by the Company during 2003. No significant declines in the amount of capacity are scheduled until the termination of the contracts in 2010.
Other operating revenues for 2003 increased $1.4 million due primarily to an increase in franchise fees. Other operating revenues for 2002 increased $6.0 million primarily due to a $3.3 million increase in franchise fees, a $1.7 million settlement related to a purchased power agreement, and a $0.9 million increase in revenues from the transmission of electricity to others.
Energy Sales
Kilowatt-hour (KWH) sales for 2003 and the percent changes by year were as follows:
KWH Percent Change ----------------------------------------------- 2003 2003 2002 2001 ----------------------------------------------- (millions) Residential 5,101 (0.8)% 9.1% (1.5)% Commercial 3,614 1.7 4.0 1.2 Industrial 2,147 4.5 1.8 4.8 Other 23 4.7 - 10.5 ----------------------------------------------- Total retail 10,885 1.0 5.9 0.6 Sales for resale Non-affiliates 2,504 16.1 3.1 22.8 Affiliates 2,439 41.8 78.4 (49.8) ----------------------------------------------- Total 15,828 8.0 10.7 (3.7) ====================================================================
Residential sales decreased 0.8 percent in 2003 primarily due to milder summer weather, when compared to 2002. In 2002, residential sales increased 9.1 percent over 2001 primarily due to more extreme summer and winter weather combined with increased summer sales along the coastal regions. Residential sales decreased 1.5 percent in 2001 primarily due to milder summer and winter weather, when compared to 2000. Residential sales are expected to increase just under 1 percent annually over the next five years, given normal weather conditions.
Commercial sales increased 1.7 percent in 2003, when compared to 2002, primarily due to increased sales along the coastal regions, in spite of milder summer weather. In 2002, commercial sales increased 4.0 percent primarily due to more extreme weather when compared to 2001. Commercial sales increased 1.2
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2003 Annual Report
percent in 2001, when compared to 2000, primarily due to increased sales along the coastal regions, in spite of milder summer weather. Commercial sales are expected to increase just under 1 percent annually over the next five years, given normal weather conditions.
Industrial sales increased 4.5 percent in 2003, when compared to 2002, primarily due to additional sales resulting from high natural gas prices. In 2002, industrial sales increased 1.8 percent, when compared to 2001, primarily due to normal customer growth. Industrial sales increased 4.8 percent in 2001, when compared to 2000, primarily due to increased sales to Real Time Pricing customers. Industrial sales are expected to increase approximately 1 percent annually over the next five years.
An increase in energy sales for resale to non-affiliates of 16.1 percent in 2003, 3.1 percent in 2002 and 22.8 percent in 2001 is primarily related to unit power sales under long-term contracts to other Florida utilities and bulk power sales under short-term contracts to other non-affiliated utilities. Fluctuations in oil and natural gas prices, which are the primary fuel sources for the unit power sales customers, influence changes in sales. However, these fluctuations in energy sales under long-term contracts have minimal effects on earnings because the energy is generally sold at variable cost. Energy sales to affiliated companies vary from year to year depending on demand and availability and cost of generating resources at each company.
Expenses
Total operating expenses in 2003 increased $51.4 million, or 7.6 percent, over the amount recorded in 2002 due primarily to higher fuel and operating costs. In 2002 total operating expenses increased $67.0 million, or 11 percent, compared to 2001 due primarily to higher fuel and maintenance costs. In 2001, total operating expenses increased $13.5 million, or 2.3 percent, from the prior year due primarily to higher purchased power expenses and maintenance expenses.
In 2003, other operation and maintenance expense increased $11 million, or 5.3 percent, primarily due to an increase of $1.6 million of customer accounts expense and an increase of $7.1 million in the accumulated provision for property damage. See Note 1 to the financial statements under "Provision for Property Damage" for additional information. In 2002, other operation and maintenance expense increased $23 million, or 12.7 percent, mainly due to scheduled generating plant maintenance. In 2001, other operation and maintenance increased by $5 million, or 2.4 percent, primarily due to increased scheduled maintenance for generating plant and transmission and distribution facilities.
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 generation resources.
In 2003, fuel expense increased $42.6 million, or 15.6 percent, when compared to 2002 due primarily to increased generation to meet the demand for energy and higher average cost of fuel. Fuel expense in 2002, when compared to 2001, increased $73.2 million, or 36.5 percent, due primarily to the commercial operation of Plant Smith Unit 3 beginning in April 2002. In 2001, fuel expenses decreased $15.1 million, or 7.0 percent, when compared to 2000 as a result of decreased generation.
The amount and sources of generation, the average cost of fuel per net kilowatt-hour generated, and the average costs of purchased power were as follows:
2003 2002 2001 ---------------------------------- Total generation (millions of kilowatt-hours) 14,988 13,142 11,423 Sources of generation (percent) Coal 86.9 81.8 99.0 Gas 13.1 18.2 1.0 Average cost of fuel per net kilowatt-hour generated (cents)-- 2.11 2.08 1.76 Average cost of purchase power per net kilowatt-hour 3.07 2.71 4.29 - ------------------------------------------------------------------------
Purchased power expense decreased in 2003 $12.3 million, or 19.5 percent, primarily due to a decrease in the volume of energy needed to meet the Company's load requirements. Purchased power expense decreased in 2002 by $43.2 million, or 40.7 percent, due primarily to the additional generating capacity from the Company's Plant Smith Unit 3. Purchased power expense for 2001 increased by $23.8 million, or 28.8 percent, due primarily to an increase in purchased power from affiliate companies.
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Fuel costs and purchases of energy will vary from year to year depending on demand and the availability and cost of generating resources. These costs do not have a significant impact on earnings, since they are generally offset by revenues through the Company's fuel cost recovery mechanism.
Depreciation and amortization expense increased $5.3 million, or 6.9 percent, in 2003 primarily due to the commercial operation of Plant Smith Unit 3 beginning in April 2002 and the amortization of a regulatory asset. Depreciation and amortization expense increased $8.8 million, or 12.9 percent, in 2002 primarily due to the commercial operation of Plant Smith Unit 3 beginning in April 2002. Depreciation and amortization expense increased $1.3 million, or 2.0 percent, in 2001 due to an increase in depreciable property and the amortization of a regulatory asset.
Allowance for equity funds used during construction decreased $2.3 million, or 76.1 percent, in 2003 and $2.4 million, or 44.5 percent, in 2002 primarily due to the completion of Plant Smith Unit 3 beginning in April 2002. See Note 1 to the financial statements under "Allowance for Funds Used During Construction and Interest Capitalized" for further information.
Interest expense decreased $0.4 million, or 1.2 percent, in 2003 due primarily to the refinancing of $173 million of senior notes and pollution control bonds at more favorable interest rates. Interest expense increased $6.4 million, or 25.6 percent, in 2002 due primarily to the issuance of $180 million of senior notes in 2001 and 2002 that were primarily used to finance the construction of Plant Smith Unit 3. In 2001, interest expense decreased $3.1 million, or 10.9 percent, due primarily to higher allowance for debt funds used during construction related to the Company's Plant Smith Unit 3, as well as lower interest rates on notes payable and variable rate pollution control bonds.
Effects of Inflation
The Company is subject to rate regulation based on the recovery of historical costs. In addition, the income tax laws are also based on historical costs. Therefore, inflation creates an economic loss because the Company is recovering its cost of investments in dollars that 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 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 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 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. These factors include the ability of the Company to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stricter environmental standards. 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.
Industry Restructuring
The Company operates as a vertically integrated utility providing electricity to 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 FPSC under cost-based regulatory principles. Retail rates and earnings are reviewed and adjusted periodically within certain limitations based on earned return on equity.
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 Policy Act of 1992 (Energy Act). The Energy Act allowed independent power producers to access a utility's transmission network and sell electricity to other utilities.
Although the Energy Act does not provide for retail customer access, it was a major catalyst for restructuring and consolidations that took place within the utility industry. Numerous federal and state initiatives that promote wholesale
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and retail competition are in varying stages. Among other things, these initiatives allow retail customers in some states to choose their electricity provider. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While various restructuring and competition initiatives have been discussed in Florida, none have been enacted. Enactment could require numerous issues to be resolved, including significant ones relating to recovery of any stranded investments, full cost recovery of energy produced, and other issues related to the energy crisis that occurred in California, as well as the August 2003 power outage in the Northeast.
In 2000, Florida's Governor appointed a study commission to look at the state's electric industry, studying issues including current and future reliability of electric and natural gas supply, retail and wholesale competition, environmental impacts of energy supply, conservation, and tax issues. The study commission's final report, entitled "Florida...Energy Wise," was presented in December 2001 to the Governor and the Legislature. The five key areas addressed by the report were Energy Efficiency, Adequate and Reliable Supply of Energy, Improvement of Energy Infrastructure, Preservation of the Environment, and Utilization of New Technologies and Renewable Resources. Changes were recommended within the wholesale energy market only. For changes to occur, legislation will have to be drafted and voted into law by the Florida Legislature. No legislation of this type has been voted on to date. The effects of any proposed changes cannot presently be determined but could have a material effect on the Company's financial condition and results of operations.
Since 2001, merchant energy companies and traditional electric utilities with significant energy marketing and trading activities have come under severe financial pressures. Many of these companies have completely exited or drastically reduced all energy marketing and trading activities and sold foreign and domestic electric infrastructure assets. The Company has not experienced any material adverse financial impact regarding its limited energy trading operations through Southern Company Services (SCS) and its recent generating capacity additions.
Continuing to be a low-cost producer could provide opportunities to increase the size and profitability of the electricity sales business in markets that evolve with changing regulation and competition. Conversely, future regulatory changes could adversely affect the Company's growth, and if the Company does not remain a low-cost producer and provide quality service, then energy sales growth could be limited, and this could significantly erode earnings.
Environmental Matters
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court in Georgia against Alabama Power, Georgia Power, and SCS. The complaint alleged violations of the New Source Review (NSR) provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. The civil action requested penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued to the retail operating companies notices of violation relating to ten generating facilities, which included the five facilities mentioned previously and the Company's Plants Crist and Scherer. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notices of violation and to add the Company, Mississippi Power, and Savannah Electric as defendants. However, in March 2001, the court denied the motion with respect to the Company and Mississippi Power based on lack of jurisdiction, and the EPA has not refiled. See Note 3 to the financial statements under "New Source Review Actions" for additional information.
In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. The December 2002 revisions included changes to the regulatory exclusions and the methods of calculating emissions increases. The October 2003 regulations clarified the scope of the existing Routine Maintenance, Repair, and Replacement exclusion. A coalition of states and environmental organizations filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. On December 24, 2003, the Court of Appeals granted a stay of the October 2003 revisions pending its review of the rules and ordered that its review be conducted on an expedited basis. In January 2004, the Bush Administration announced that it
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would continue to enforce the existing rules until the courts resolve legal challenges to the EPA's revised NSR regulations. In any event, the final regulations must be adopted by the state of Florida in order to apply to the Company's facilities. The effect of these final regulations and the related legal challenges cannot be determined at this time.
The Company believes that it has complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
Environmental Statutes and Regulations
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. Compliance with these environmental requirements will involve significant costs - -- both capital and operating -- a major portion of which is expected to be recovered through existing ratemaking provisions. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under "Capital Requirements and Contractual Obligations." The Florida Legislature has adopted legislation that allows a utility to petition the FPSC for specific 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 "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. There is no assurance however, that all such costs will, in fact, be recovered.
Compliance with the federal Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. The Title IV acid rain provisions of the Clean Air Act, for example, required significant reductions in sulfur dioxide and nitrogen oxide emissions. Title IV compliance was effective in 2000 and associated construction expenditures totaled approximately $42 million for the Company.
In July 1997, the EPA revised the national ambient air quality standards for ozone and particulate matter. These revisions made the standards significantly more stringent. In the subsequent litigation of these standards, the U.S. Supreme Court found the EPA's implementation program for the new eight-hour ozone standard unlawful and remanded it to the EPA for further rulemaking. During 2003, the EPA proposed implementation rules designed to address the court's concerns.
Based on recommendations from the State, the EPA is expected to designate areas of Florida as attainment or nonattainment with the new eight-hour ozone and particulate standards in April 2004 and with the new fine particulate matter standard by the end of 2004. In August 2002, the Company entered into an agreement with the Florida Department of Environmental Protection (FDEP) calling for nitrogen oxide (NOx) emission reductions at Plant Crist to help ensure attainment of the new standards in the Pensacola area. Under the agreement, the Company will install Selective Catalytic Reduction controls and a new precipitator on Plant Crist Unit 7 by 2005. In addition, the Company agreed to retire Plant Crist Unit 1 in 2003 and Units 2 and 3 by 2006. The conditions of the agreement will be fully implemented by 2006 at a cost of approximately $133 million, of which $99 million remains to be spent. Costs for implementation of the agreement have been approved for recovery through the Environmental Cost Recovery Clause.
In January 2004, the EPA issued a proposed Interstate Air Quality Rule to address interstate transport of ozone and fine particles. This proposed rule would require additional year-round sulfur dioxide and nitrogen oxide emission reductions from power plants in the eastern United States in two phases - in 2010 and 2015. The EPA currently plans to finalize this rule by 2005. If finalized, the rule could modify or supplant other State Implementation Plan (SIP) requirements for attainment of the fine particulate matter standard and the eight-hour ozone standard. The impact of this rule on the Company will depend upon the specific requirements of the final rule and cannot be determined at this time.
Further reductions in sulfur dioxide and nitrogen oxides could also be required under the EPA's Regional Haze rules. The Regional Haze rules require states to establish Best Available Retrofit Technology (BART) standards for certain sources that contribute to regional haze. The Company has a number of plants that could be subject to these rules. The EPA's Regional Haze program
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calls for states to submit SIPs in 2007. The SIPs must contain emission reduction strategies for implementing BART and achieving progress toward the Clean Air Act's visibility improvement goal. In 2002, however, the U.S. Court of Appeals for the District of Columbia Circuit vacated and remanded the BART provisions of the federal Regional Haze rules to the EPA for further rulemaking. The EPA has entered into an agreement that requires proposed revised rules in April 2004 and final rules in 2005. Because new BART rules have not been developed and state visibility assessments for progress are only beginning, it is not possible to determine the effect of these rules on the Company at this time.
The EPA's Compliance Assurance Monitoring (CAM) regulations under Title V of the Clean Air Act require that monitoring be performed to ensure compliance with emissions limitations on an ongoing basis. In 2004 and 2005, a number of the Company's plants will likely become subject to CAM requirements for at least one pollutant, in most cases, particulate matter. The Company is in the process of developing CAM plans. Because the plans are still under development, the Company cannot determine the costs associated with implementation of the CAM regulations at this time. Actual ongoing monitoring costs are expensed as incurred and are not material for any year presented.
In January 2004, the EPA issued proposed rules regulating mercury emissions from electric utility boilers. The proposal solicits comments on two possible approaches for the new regulations - a Maximum Achievable Control Technology approach and a cap-and-trade approach. Either approach would require significant reductions in mercury emissions from company facilities. The regulations are scheduled to be finalized by the end of 2004, and compliance could be required as early as 2007. Because the regulations have not been finalized, the impact on the Company cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent emissions limitations on power plants have been proposed by Congress. Three of these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2003, and the Clean Air Planning Act of 2003, propose to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills also propose to limit emissions of carbon dioxide. The cost impacts of such legislation would depend upon the specific requirements enacted and cannot be determined at this time.
Domestic efforts to limit greenhouse gas emissions have been spurred by international discussions surrounding the Framework Convention on Climate Change and specifically the Kyoto Protocol, which proposes international constraints on the emissions of greenhouse gases. The Bush Administration does not support U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation and has instead announced a new voluntary climate initiative, known as Climate VISION, which seeks an 18 percent reduction by 2012 in the rate of greenhouse gas emissions relative to the dollar value of the U.S. economy. Through Southern Company, the Company is involved in a voluntary electric utility industry sector climate change initiative in partnership with the government. The electric utility sector has pledged to reduce its greenhouse gas intensity 3 to 5 percent over the next decade and is in the process of developing a memorandum of understanding with the Department of Energy (DOE) to cover this voluntary program.
The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs for clean up and ongoing monitoring of known sites. Amounts for clean up 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.
Under the Clean Water Act, the EPA has been developing new rules aimed at reducing impingement and entrainment of fish and fish larvae at power plants cooling water intake structures. On February 16, 2004, the EPA finalized these rules. These rules will require biological studies and, perhaps, retrofits to some intake structures at existing power plants. The impact of these new rules will depend on the results of studies and analyses performed as part of the rules' implementation.
In addition, under the Clean Water Act, the EPA and the FDEP are developing total maximum daily loads (TMDLs) for certain impaired waters. Establishment of maximum loads by the EPA or the FDEP may result in lowering permit limits for various pollutants and a requirement to take additional measures to control non-point source pollution (e.g. storm water runoff) at facilities that
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discharge into waters for which TMDLs are established. Because the effect on the Company will depend on the actual TMDLs and permit limitations established by the implementing agency, it is not possible to determine the effect on the Company at this time.
Several major pieces of environmental legislation are periodically considered for reauthorization or amendment by Congress. These 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 possible additional federal or state legislation or regulations related to global climate change, electromagnetic fields or other environmental and health concerns could also significantly affect the Company. The impact of any new legislation, changes to existing legislation, or environmental regulations could affect many areas of the Company's operations. The full impact of any such changes cannot, however, be determined at this time.
FERC Matters
Transmission
In December 1999, the Federal Energy Regulatory Commission (FERC) issued its final rule (Order 2000) on Regional Transmission Organizations (RTOs). Order 2000 encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Southern Company and its retail operating companies, including the Company, worked with a number of utilities in the Southeast to develop a for-profit RTO known as SeTrans. In 2002, the sponsors of SeTrans established a Stakeholder Advisory Committee to provide input into the development of the RTO from other sectors of the electric industry, as well as consumers. During the development of SeTrans, state regulatory authorities expressed concern over certain aspects of the FERC's policies regarding RTOs. In December 2003, the SeTrans sponsors announced that they would suspend work on SeTrans because the regulated utility participants, including the Company, had determined that they were highly unlikely to obtain support of both federal and state regulatory authorities. Any impact of the FERC's rule on the Company will depend on the regulatory reaction to the suspension of SeTrans and future developments, which cannot now be determined.
In July 2002, the FERC issued a notice of proposed rulemaking regarding open access transmission service and standard electricity market design. The proposal, if adopted, would among other things: (1) require transmission assets of jurisdictional utilities to be operated by an independent entity; (2) establish a standard market design; (3) establish a single type of transmission service that applies to all customers; (4) assert jurisdiction over the transmission component of bundled retail service; (5) establish a generation reserve margin; (6) establish bid caps for day ahead and spot energy markets; and (7) revise the FERC policy on the pricing of transmission expansions. Comments on the proposal were submitted by many interested parties, including Southern Company, and the FERC has indicated that it has revised certain aspects of the proposal in response to public comments. Proposed energy legislation would prohibit the FERC from issuing the final rule before October 31, 2006, and from making any final rule effective before December 31, 2006. That legislation has been approved by the House of Representatives but remains pending before the Senate. Passage of the legislation now appears in doubt. It is uncertain whether in the absence of legislation the FERC will move forward with any part or all of the proposed rule. Any impact of this proposal on the Company will depend on the form in which the final rule may be ultimately adopted. However, the Company's financial statements could be adversely affected by changes in the transmission regulatory structure in its regional power market.
Market-Based Rate Authority
The Company has obtained FERC approval to sell power to nonaffiliates at market-based prices under specific contracts. Through SCS, as agent, the Company also has the FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities' applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company's retail operating companies, and found them to be "pivotal suppliers" in their service areas. SCS, on behalf of the Company and the other retail operating companies, sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. SCS, on behalf of the Company and the other retail operating companies, submitted comments to the FERC in 2002 regarding these issues. In
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December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. The Company anticipates that the FERC will address the requests for rehearing in the near future. Regardless of the outcome of the SMA proposal, the FERC retains the ability to modify or withdraw the authorization for any seller to sell at market-based rates if it determines that the underlying conditions for having such authority are no longer applicable. The final outcome of this matter will depend on the form in which the SMA test and mitigation measures rules may be ultimately adopted and cannot be determined at this time.
Other Matters
In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash pension income, before tax, of approximately $4.9 million, $5.6 million, and $5.9 million in 2003, 2002, and 2001, respectively. Future pension income is dependent on several factors including trust earnings and changes to the plan. The decline in pension income is expected to continue and become an expense as early as 2006. Postretirement benefit costs for the Company were $4.9 million, $4.5 million, and $4.5 million in 2003, 2002, and 2001, respectively, and are expected to continue to trend upward. A portion of pension income and postretirement benefit costs is capitalized based on construction-related labor charges. Pension income or expense and postretirement benefit costs are components 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.
On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act). The Medicare Act introduces a prescription drug benefit for Medicare-eligible retirees starting in 2006, as well as a federal subsidy to plan sponsors like the Company that provide prescription drug benefits. In accordance with FASB Staff Position No. 106-1, the Company has elected to defer recognizing the effects of the Medicare Act for its postretirement plans under FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other than Pension until authoritative guidance on accounting for the federal subsidy is issued or until a significant event occurs that would require remeasurement of the plans' assets and obligations. The Company anticipates that the benefits it pays after 2006 will be lower as a result of the Medicare Act; however, the retiree medical obligations and costs reported in Note 2 to the financial statements do not reflect these changes. The final accounting guidance could require changes to previously reported information.
In May 2002, the FPSC approved a retail base rate increase of $53.2 million effective June 7, 2002, the majority of which was related to Plant Smith Unit 3, which was placed in service beginning in April 2002. See Note 3 to the financial statements for additional information about these and other regulatory matters.
The FPSC has approved a revised rule for investor-owned utilities engaging in power plant construction subject to the Florida Electrical Power Plant Siting Act (PPSA) to govern the process for selecting such generation projects. This new rule is aimed at creating a more transparent process accessible to a greater number of bidders. The revisions require a utility that intends to build a project subject to the PPSA to first issue a request for proposals (RFP) that meets the requirements of the revised rule, including a more detailed description of the methodology and criteria that will be used to evaluate the response. Also, respondents that have not been eliminated from further consideration must be given an opportunity to revise their proposals if the utility intends to revise its cost estimates on which the RFP was based. The revised rule also provides a mechanism for expedited dispute resolution and places restrictions on the level of costs a utility may recover if, at the conclusion of the RFP process, the FPSC certifies the utility's own self-build option as the most cost effective generation alternative identified through the process. The new rule was made effective June 17, 2003.
The FPSC, in collaboration with the FDEP, was directed by the Florida Legislature to prepare a report on renewable energy. A final report was prepared by the FPSC and the FDEP in January 2003. This report describes various renewable and green energy options. The report provided the FPSC, the FDEP, and the Florida Legislature with information on current and potential technologies, costs, feasibility, and status of current renewable technologies within the State of Florida. The report does not provide any formal policy recommendations with respect to renewable energy but is intended to provide the Legislature and policymakers a sound starting point if they consider new legislation in this
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area. While the Company is actively pursuing a renewable energy portfolio that may be incorporated into its offering to its customers, the pursuit of a mandatory renewable portfolio standard or a benefits charge that could not be passed on to customers by the state could add additional costs to the Company's operations and affect the Company's competitive position.
The Company is involved in various matters being litigated and regulatory matters that could affect future earnings. 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 discussed the development and selection of the critical accounting policies and estimates described below with the Controls and Compliance Committee of the Company's Board of Directors and the Audit Committee of Southern Company's Board of Directors.
Electric Utility Regulation
The Company is subject to retail regulation by the FPSC 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. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of Statement No. 71 has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and post-retirement 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. However, adverse legislation and 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" 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:
o 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. o Changes in existing income tax regulations or changes in Internal Revenue Service interpretations of existing regulations. o 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. o Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant. o Resolution or progression of existing matters through the legislative process, the court systems, or the EPA.
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New Accounting Standards
Prior to January 2003, the Company accrued for the ultimate cost of retiring most long-lived assets over the life of the related asset through depreciation expense. FASB Statement No. 143, Accounting for Asset Retirement Obligations, established new accounting and reporting standards for legal obligations associated with the ultimate cost of retiring long-lived assets. 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 cost is capitalized as part of the related long-lived asset and depreciated over the asset's useful life. For more information regarding the impact of adopting this standard effective January 1, 2003, see Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal."
FASB Statement No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, which further amends and clarifies the accounting and reporting for derivative instruments, became effective generally for financial instruments entered into or modified after June 30, 2003. Current interpretations of Statement No. 149 indicate that certain electricity forward transactions subject to unplanned netting -- including those typically referred to as "book outs" -- may only qualify as cash flow hedges if an entity can demonstrate that physical delivery or receipt of power occurred. The Company's forward electricity contracts continue to be exempt from fair value accounting requirements or to qualify as cash flow hedges. The implementation of Statement No. 149 did not have a material effect on the Company's financial statements.
In July 2003, the Emerging Issues Task Force (EITF) of FASB issued EITF No. 03-11, which became effective on October 1, 2003. The standard addresses the reporting of realized gains and losses on derivative instruments and is being interpreted to require book outs to be recorded on a net basis in operating revenues. Adoption of this standard did not have a material impact on the Company's financial statements.
FASB Interpretation No. 46, Consolidation of Variable Interest Entities, which was originally issued in January 2003, requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. In December 2003, the FASB revised Interpretation No. 46 and deferred the effective date until March 31, 2004 for interests held in variable interest entities other than special purpose entities.
Current analysis indicates that the trusts established by the Company to issue preferred securities are variable interest entities under Interpretation No. 46, and that the Company is not the primary beneficiary of these trusts. If this conclusion is finalized, effective March 31, 2004, the trust assets and liabilities-- including the preferred securities issued by the trusts-- will be deconsolidated. The investments in the trusts and the loans from the trusts to the Company will be reflected as equity method investments and as long-term notes payable to affiliates, respectively, on the Balance Sheets. Based on December 31, 2003 values, this treatment would result in an increase of approximately $2.2 million to both total assets and total liabilities. See Note 6 to the financial statements under "Mandatorily Redeemable Preferred Securities" for additional information.
In May 2003, the FASB issued Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity, which requires classification of certain financial instruments within its scope, including shares that are mandatorily redeemable, as liabilities. Statement No. 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise on July 1, 2003. In accordance with Statement No. 150, mandatorily redeemable preferred securities are reflected on the Balance Sheets as liabilities. The adoption of Statement No. 150 had no impact on the Statements of Income and Cash Flows.
FINANCIAL CONDITION AND LIQUIDITY - ---------------------------------
Overview
The Company's financial condition continues to be strong. The Company operated at high levels of reliability while achieving industry-leading customer satisfaction levels and continuing to have retail prices below the national average.
The Company's ratio of common equity to total capitalization -- including short-term debt -- was 45.3 percent in 2003, 44.0 percent in 2002, and 42.8 percent in 2001. See Note 6 to the financial statements for additional information.
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During 2003, gross property additions were $99 million. Funds for the Company's property additions were provided by operating activities, capital contributions, and other financing activities. See the Statements of Cash Flows for additional information.
Sources of Capital
The Company plans to obtain the funds required for construction and other purposes, including compliance with environmental regulations, from sources similar to those used in the past. These sources include operating cash flow, the issuance of unsecured debt and preferred securities, in addition to pollution control revenue bonds issued for the Company's benefit by public authorities. However, the type and timing of any future financings--if needed--will depend on market conditions and regulatory approval.
The Company has no restrictions on the amounts of unsecured indebtedness it may incur. However, the Company is required to meet certain coverage requirements specified in its mortgage indenture and corporate charter to issue new first mortgage bonds and preferred stock. The Company's coverage ratios are high enough to permit, at present interest rate levels, any foreseeable security sales. The amount of securities which the Company will be permitted to issue in the future will depend upon market conditions and other factors prevailing at that time.
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. In accordance with the Public Utility Holding Company Act, most loans between affiliated companies must be approved in advance by the Securities and Exchange Commission (SEC).
To meet short-term cash needs and contingencies, the Company has various internal and external sources of liquidity. At the beginning of 2004, the Company had approximately $2.5 million of cash and cash equivalents, along with $56.0 million of unused committed lines of credit with banks to meet its short-term cash needs. In addition, the Company has substantial cash flow from operating activities.
At the beginning of 2004, the Company had used none of its available credit arrangements. Bank credit arrangements are as follows:
Expires Total Unused 2004 2005 & beyond - ---------------------------------------------------------------- (in millions) $56.0 $56.0 $56.0 $- - ----------------------------------------------------------------
See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other Southern Company retail operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other operating company. There is no cross affiliate credit support. At December 31, 2003, the Company had outstanding $37.7 million of commercial paper.
Financing Activities
During 2003, the Company issued $286.6 million of long-term debt. The issuances were used to refund $173.3 million of long-term debt and $45 million of mandatorily redeemable preferred securities and to pay at maturity $60 million of senior notes due August 1, 2003. The remainder was used to reduce short-term debt.
Credit Rating Risk
The Company does not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
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. Derivative positions are monitored using techniques that include market valuation and sensitivity analysis.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2003 Annual Report
To mitigate exposure to interest rates, the Company has entered into an interest rate swap that was designated as a hedge. The weighted average interest rate on $145 million variable long-term debt that has not been hedged outstanding at December 31, 2003 was 1.2 percent. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $1.4 million at December 31, 2003. The Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term. For further information, see Notes 1 and 6 to the financial statements under "Financial Instruments."
The fair value of changes in energy-related derivative contracts and year-end valuations were as follows at December 31:
Changes in Fair Value - ---------------------------------------------------------------- 2003 2002 - ---------------------------------------------------------------- (in thousands) Contracts beginning of year $ 2,326 $ (110) Contracts realized or settled (5,098) 150 New contracts at inception - - Changes in valuation techniques - - Current period changes 5,265 2,296 - ---------------------------------------------------------------- Contracts end of year $ 2,493 $2,336 ================================================================
Source of 2003 Year-End Valuation Prices - ---------------------------------------------------------------- Total Maturity Fair Value 2004 2005-2006 - ---------------------------------------------------------------- (in thousands) Actively quoted $2,503 $2,671 $(168) External source - - - Models and other methods - - - - ---------------------------------------------------------------- Contracts end of year $2,503 $2,671 $(168) ================================================================
Unrealized gains and losses from mark to market adjustments on derivative contracts related to the Company's fuel hedging programs are recorded as regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are recovered through the Company's fuel cost recovery clause. Gains and losses on derivative contracts that are not designated as hedges are recognized in the Income Statement as incurred. For the years ended December 31, 2003, 2002, and 2001, these amounts were not material. At December 31, 2003, the fair value of derivative energy contracts was reflected in the financial statements as follows:
Amounts - ---------------------------------------------------------------- (in thousands) Regulatory liabilities, net $2,501 Other comprehensive income - Net income 2 - ---------------------------------------------------------------- Total fair value $2,503 ================================================================
Unrealized gains (losses) recognized in income in 2003 and 2002 were not material. 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 $166 million in 2004, $149 million in 2005, and $108 million in 2006. These amounts include $64 million, $31 million, and $4 million in 2004, 2005, and 2006, respectively, for capital expenditures related to environmental controls at Plant Crist as part of an agreement with the FDEP to reduce NOx emissions. The FPSC authorized the Company to recover the costs related to these environmental projects through the Environmental Cost Recovery Clause. Actual construction costs may vary from this estimate because of changes in such factors as the following: business conditions; environmental regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
The Company does not have any new generating capacity scheduled to be placed in service through 2006. 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 are ongoing.
As discussed in Note 2 to the financial statements, the Company provides post retirement benefits to substantially all employees and funds trusts to the extent required by the FERC.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2003 Annual Report
Other funding requirements related to obligations associated with scheduled maturities of long-term debt and preferred securities, as well as the related interest and distributions, preferred 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) Gulf Power Company 2003 Annual Report
Cautionary Statement Regarding Forward-Looking Information
The Company's 2003 Annual Report includes forward-looking statements in addition to historical information. Forward-looking information includes, among other things, statements concerning the estimated construction and other expenditures and the Company's projections for energy sales. 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 comparable terminology. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
o 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 and also changes in environmental, tax, and other laws and regulations to which the Company are subject, as well as changes in application of existing laws and regulations; o current and future litigation, regulatory investigations, proceedings, or inquiries, including current IRS audits; o the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates; o the impact of fluctuations in commodity prices, interest rates, and customer demand; o available sources and costs of fuels; o ability to control costs; o investment performance of the Company's employee benefit plans; o advances in technology; o state and federal rate regulations and pending and future rate cases and negotiations; o effects of and changes in political, legal, and economic conditions and developments in the United States, including the current soft economy; o potential business strategies, including acquisitions or dispositions of assets, which cannot be assured to be completed or beneficial to the Company; o the ability of counterparties of the Company to make payments as and when due; o the ability to obtain new short- and long-term contracts with neighboring utilities: o the direct or indirect effects on the Company's business resulting from the terrorist incidents on September 11, 2001, or any similar incidents or responses to such incidents; o financial market conditions and the results of financing efforts, including the Company's credit ratings; o the ability of the Company to obtain additional generating capacity at competitive prices; o weather and other natural phenomena; o the direct or indirect effects on the Company's business resulting from the August 2003 power outage in the Northeast, or any similar incidents; o the effect of accounting pronouncements issued periodically by standard-setting bodies; and o other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed from time to time by the Company with the SEC.
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NOTES TO FINANCIAL STATEMENTS Gulf Power Company 2003 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 five retail operating companies, Southern Power Company (Southern Power), Southern Company Services (SCS), Southern Communications Services (Southern LINC), Southern Company Gas (Southern Company GAS), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The retail operating companies - Alabama Power, Georgia Power, the Company, Mississippi Power, and Savannah Electric - provide electric service in four Southeastern states. The Company operates as a vertically integrated utility providing service to customers in northwest Florida and to wholesale customers in the Southeast. Southern Power constructs, owns, and manages Southern Company's competitive generation assets and sells electricity at market-based rates in the wholesale market. Contracts among the retail operating companies and Southern Power - related to jointly owned generating facilities, interconnecting transmission lines, or the exchange of electric power - are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission (SEC). SCS, the system service company, provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern Company GAS is a competitive retail natural gas marketer serving customers in Georgia. Southern Holdings is an intermediate holding subsidiary for Southern Company's investments in synthetic fuels and leveraged leases, and an energy services business. Southern Nuclear operates and provides services to Southern Company's nuclear power plants.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries, including the Company, are subject to the regulatory provisions of the PUHCA. The Company is also subject to regulation by the FERC and the Florida Public Service Commission (FPSC). 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.
Certain prior years' data presented in the financial statements have been reclassified to conform with current year presentation.
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 $56 million, $49 million, and $45 million during 2003, 2002, and 2001, respectively. Cost allocation methodologies used by SCS are approved by the SEC and management believes they are reasonable.
The Company has agreements with Georgia Power and Mississippi Power under which the Company owns a portion of Plant Scherer and Plant Daniel. Georgia Power operates Plant Scherer and Mississippi Power operates Plant Daniel. The Company reimbursed Georgia Power $5.6 million and $4.5 million and Mississippi Power $17.7 million and $16.6 million in 2003 and 2002, respectively, for its proportionate share of related expenses. See Note 7 under "Operating Leases" for additional information.
The retail operating companies (including the Company), Southern Power, and Southern Company GAS 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.
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NOTES (continued) Gulf Power Company 2003 Annual Report
Revenues and Regulatory Cost Recovery Clauses
Revenues are recognized as services are rendered. Unbilled revenues are accrued at the end of each fiscal period. Fuel costs are expensed as the fuel is used. The Company's retail electric rates include provisions to annually adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. The Company has similar retail cost recovery clauses for energy conservation costs, purchased power capacity costs, and environmental compliance costs. Revenues are adjusted monthly for differences between recoverable costs and amounts actually reflected in current rates.
The Company has a diversified base of customers and no single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts averaged significantly less than 1 percent of revenues.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the Balance Sheets at December 31 relate to:
2003 2002 Note - ---------------------------------------------------------------- (in thousands) Asset retirement obligations $ 1,019 $ - (a) Other cost of removal obligations (151,229) (143,060) (a) Deferred income tax charges 18,263 18,798 (a) Loss on reacquired debt 19,389 14,052 (b) Vacation pay 5,254 5,044 (c) Deferred income tax credits (26,545) (29,692) (a) Accumulated provision for property damage (26,244) (15,418) (d) Environmental remediation 12,878 14,429 (f) Fuel-hedging liabilities (2,501) (2,322) (e) Other assets 8,198 2,859 (d) Other liabilities (3,177) (3,351) (d) - ------------------------------------------------------- Total $(144,695) $(138,661) ======================================================= 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 by the FPSC. (e) Fuel-hedging 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 fuel cost recovery clause. (f) Recovered through the Environmental Cost Recovery Clause (ECRC) when the expense is incurred. The estimated completion date for this project is currently 2012.
In the event that a portion of the Company's operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair value. All regulatory assets and liabilities are reflected in rates.
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.8 percent in 2003, 3.9 percent in 2002, and 3.7 percent in 2001. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost -
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together with the cost of removal, less salvage - is charged to the accumulated provision for depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.
Asset Retirement Obligations and Other Costs of Removal
In accordance with regulatory requirements, prior to January 2003, the Company followed the industry practice of accruing for the ultimate cost of retiring most long-lived assets over the life of the related asset as part of the annual depreciation expense provision. In accordance with SEC requirements, such amounts are reflected on the balance sheet as regulatory liabilities.
Effective January 1, 2003, the Company adopted FASB Statement No. 143, Accounting for Asset Retirement Obligations. Statement No. 143 establishes new accounting and reporting standards for legal obligations associated with the ultimate cost of retiring long-lived assets. The ultimate cost for an asset's future retirement must be recorded in the period in which the liability is incurred. The cost must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Additionally, Statement No. 143 does not permit the continued accrual of future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. At the time of adoption, the Company had received guidance regarding accounting for the financial statement impacts of Statement No. 143 from the FPSC and in accordance with that guidance had no cumulative effect to net income resulting from the adoption of Statement No. 143. The Company will continue to recognize the accumulated removal costs for other obligations as a regulatory liability.
The liability recognized under Statement No. 143 to retire long-lived assets primarily relates to the Company's combustion turbines at its Pea Ridge facility, various landfill sites, ash ponds, and a barge unloading dock. The Company has also identified retirement obligations related to certain transmission and distribution facilities. However, liabilities for the removal of these transmission and distribution assets have not been recorded because no reasonable estimate can be made regarding the timing of the obligations. The Company will continue to recognize in the Income Statement allowed removal costs in accordance with its regulatory treatment. Any difference between costs recognized under Statement No. 143 and those reflected in rates are recognized as either a regulatory asset or liability and are reflected in the Balance Sheets.
Details of the asset retirement obligations included in the Balance Sheets are as follows: - ------------------------------------------------------------------- (in millions) Balance beginning of year $ - Liabilities incurred 4.0 Liabilities settled - Accretion 0.3 Cash flow revisions - - ------------------------------------------------------------------- Balance end of year $4.3 ===================================================================
If Statement No. 143 had been adopted on January 1, 2002, the pro-forma asset retirement obligations would have been $3.7 million.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized
In accordance with regulatory treatment, the Company records AFUDC on construction projects. AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. For the years, 2003, 2002, and 2001 the average AFUDC rates were 7.48 percent, 7.35 percent, and 7.35 percent, respectively. AFUDC, net of taxes, as a percentage of net income after dividends on preferred stock was 1.31 percent, 5.72 percent, and 11.86 percent, respectively for, 2003, 2002, and 2001.
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 estimated cost of funds used during construction. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense. The cost of replacements of property (exclusive of minor items of property) is charged to utility plant.
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NOTES (continued) Gulf Power Company 2003 Annual Report
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 to 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 provision for loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared with the estimated fair value less the cost to sell in order to determine if an impairment provision is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
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 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.
Stock Options
Southern Company provides non-qualified stock options to a large segment of the Company's employees ranging from line management to executives. The Company accounts for its stock-based compensation plans in accordance with Accounting Principles Board Opinion No. 25. Accordingly, no compensation expense has been recognized because the exercise price of all options granted equaled the fair-market value on the date of grant. When options are exercised, the Company receives a capital contribution from Southern Company equivalent to the related income tax benefit.
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 or regulatory assets or liabilities as appropriate 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.
Other financial instruments for which the carrying amount does not equal fair value at December 31 were as follows:
Carrying Fair Amount Value - ------------------------------------------------------------------- (in thousands) Long-term debt: At December 31, 2003 $565,827 $572,899 At December 31, 2002 512,040 531,133 Preferred Securities At December 31, 2003 $ 70,000 $ 73,376 At December 31, 2002 155,000 156,853 - -------------------------------------------------------------------
The fair values were based on either closing market price or closing price of comparable instruments.
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NOTES (continued) Gulf Power Company 2003 Annual Report
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 changes in additional minimum pension liability, less income taxes and reclassifications for amounts included in net income.
Provision for Injuries and Damages
The Company is subject to claims and suits arising in the ordinary course of business. As permitted by regulatory authorities, the Company provides for the uninsured costs of injuries and damages by charges to income amounting to $1.2 million annually. The cost of settling claims is charged to a provision account. The accumulated provision of $0.1 million and $0.7 million at December 31, 2003 and 2002, respectively, is included in other current liabilities in the accompanying Balance Sheets. For further information, see Note 3 under "Personal Injury Litigation." In addition to the provision, at December 31, 2003, the Company recorded a liability with a corresponding regulatory asset of $6.9 million for estimated liabilities related to outstanding claims and suits.
Provision for Property Damage
The Company provides for the cost of repairing damages from major storms and other uninsured property damages. This includes the cost of major storms and other damages to its transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property. The expense of such damages is charged to the provision account. At December 31, 2003 and 2002, the accumulated provision for property damage was $26.2 million and $15.5 million, respectively, and is included in miscellaneous regulatory liabilities in the accompanying Balance Sheets. The FPSC approved annual accrual to the accumulated provision for property damage is $3.5 million, with a target level for the accumulated provision account between $25.1 million and $36.0 million. The FPSC had also given the Company the flexibility to increase its annual accrual amount above $3.5 million at the Company's discretion. The Company accrued $10.6 million in 2003, $3.5 million in 2002, and $4.5 million in 2001 to the accumulated provision for property damage.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with Employee Retirement Income Security Act (ERISA) requirements. No contributions to the plan are expected for the year ending December 31, 2004. The Company also provides certain non-qualified benefit plans for a selected group of management and highly compensated employees. Benefits under these non-qualified plans are funded on a cash basis. The Company provides certain medical care and life insurance benefits for retired employees. In addition, trusts are funded to the extent required by the FPSC and the FERC. For the year ended December 31, 2004, postretirement benefit contributions are expected to total approximately $80 thousand.
The measurement date for plan assets and obligations is September 30 of each year. In 2002, the Company adopted plan changes that had the effect of increasing benefits to both current and future retirees.
Pension Plans
The accumulated benefit obligation for the pension plans was $186 million in 2003 and $162 million in 2002. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:
Projected Benefit Obligations --------------------------- 2003 2002 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $184,987 $169,251 Service cost 5,225 4,910 Interest cost 11,733 12,394 Benefits paid (8,785) (8,395) Actuarial (gain)/loss and employee transfers, net 13,326 2,672 Other - 4,155 - --------------------------------------------------------------- Balance at end of year $206,486 $184,987 ===============================================================
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Plan Assets 2003 2002 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $211,166 $233,706 Actual return on plan assets 33,672 (15,694) Benefits paid (8,293) (7,934) Employee transfers (199) 1,088 - ---------------------------------------------------------------- Balance at end of year $236,346 $211,166 ===============================================================
Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Service (IRS) revenue code. The Company's investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.
Plan Assets --------------------------------- Target 2003 2002 - ----------------------------------------------------------------- Domestic equity 37% 37% 35% International equity 20 20 18 Global fixed income 26 24 25 Real estate 10 11 12 Private equity 7 8 10 - ----------------------------------------------------------------- Total 100% 100% 100% =================================================================
The accrued pension costs recognized in the Balance Sheets were as follows: Accrued Pension Costs ---------------------- 2003 2002 - ------------------------------------------------------------- (in thousands) Funded status $29,859 $26,179 Unrecognized transition obligation (1,440) (2,161) Unrecognized prior service cost 13,471 14,874 Unrecognized net gain (4,155) (6,589) 4th quarter cash flow adjustment 169 85 - ------------------------------------------------------------- Prepaid pension asset, net 37,904 32,388 Portion included in benefit obligations 4,110 3,910 - ------------------------------------------------------------- Total Prepaid asset recognized in the Balance Sheets $42,014 $36,298 =============================================================
In 2003 and 2002, amounts recognized in the Balance Sheets for accumulated other comprehensive income and intangible assets to record the minimum pension liability related to the non-qualified plans were $1.4 million and $0.7 million and $1.2 million and $0.9 million, respectively.
Components of the pension plans' net periodic cost were as follows:
2003 2002 2001 - ------------------------------------------------------------------- (in thousands) Service cost $ 5,225 $ 4,910 $ 4,703 Interest cost 11,733 12,394 11,644 Expected return on plan assets (20,564) (20,431) (19,312) Recognized net gain (1,819) (2,746) (3,072) Net amortization 486 298 165 - ------------------------------------------------------------------- Net pension income $ (4,939) $ (5,575) $ (5,872) ===================================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:
Accumulated Benefit Obligations --------------------------- 2003 2002 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $63,675 $54,337 Service cost 1,128 948 Interest cost 4,059 3,992 Benefits paid (2,332) (1,984) Actuarial (gain)/loss 6,373 6,382 - --------------------------------------------------------------- Balance at end of year $72,903 $63,675 ===============================================================
Plan Assets --------------------------- 2003 2002 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $10,893 $11,632 Actual return on plan assets 1,616 (793) Employer contributions 2,465 2,038 Benefits paid (2,332) (1,984) - --------------------------------------------------------------- Balance at end of year $12,642 $10,893 ===============================================================
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Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the IRS revenue code. The Company's investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.
Plan Assets ------------------------------- Target 2003 2002 - ---------------------------------------------------------------- Domestic equity 35% 35% 32% International equity 19 19 18 Global fixed income 31 29 30 Real estate 9 10 11 Private equity 6 7 9 - ---------------------------------------------------------------- Total 100% 100% 100% ================================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows:
2003 2002 - -------------------------------------------------------------- (in thousands) Funded status $(60,261) $(52,782) Unrecognized transition obligation 3,301 3,656 Unrecognized prior service cost 5,003 5,349 Unrecognized net loss 15,313 9,530 Fourth quarter contributions 195 581 - -------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $(36,449) $(33,666) ==============================================================
Components of the postretirement plan's net periodic cost were as follows:
2003 2002 2001 - ----------------------------------------------------------------- Service cost $ 1,128 $ 948 $ 983 Interest cost 4,058 3,991 3,886 Expected return on plan assets (1,139) (1,100) (1,037) Transition obligation 356 356 356 Prior service cost 346 346 299 Recognized net (gain)/loss 113 (19) (18) - ----------------------------------------------------------------- Net post-retirement cost $ 4,862 $ 4,522 $ 4,469 =================================================================
The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations and the net period costs for the pension and postretirement benefit plans were as folows:
2003 2002 2001 - ------------------------------------------------------------------ Discount 6.00% 6.50% 7.50% Annual salary increase 3.75% 4.00% 5.00% Long-term return on plan assets 8.50% 8.50% 8.50% - ------------------------------------------------------------------
The Company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.
An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 8.25 percent for 2003, decreasing gradually to 5.25 percent through the year 2010 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2003 as follows:
1 Percent --------------------------- Increase Decrease - --------------------------------------------------------------- (in thousands) Benefit obligation $5,601 $4,949 Service and interest costs $ 364 $ 320 ===============================================================
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee's base salary. Total matching contributions made to the plan for the years 2003, 2002, and 2001, were $2.6 million, $2.5 million, and $2.3 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
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subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements, 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 litigation against the Company cannot be predicted at this time; however, 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 Cost Recovery
In 1993, the Florida Legislature adopted legislation for an Environmental Cost Recovery Clause (ECRC), which allows an electric utility to petition the FPSC 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 was amended in 2002 to allow recovery of costs incurred as a result of an agreement between the Company and the Florida Department of Environmental Protection (FDEP) for the purpose of ensuring compliance with ozone ambient air quality standards adopted by the Environmental Protection Agency (EPA). During 2003, 2002, and 2001, the Company recorded ECRC revenues of $10.7 million, $10.8 million, and $10.0 million, respectively.
At December 31, 2003, the Company's liability for the estimated costs of environmental remediation projects for known sites was $12.9 million. These estimated costs are expected to be expended from 2004 through 2012. These projects have been approved by the FPSC for recovery through the ECRC discussed above. Therefore, the Company recorded $1.3 million in current assets and current liabilities and $11.6 million in deferred assets and deferred liabilities representing the future recoverability of these costs.
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 Alabama Power, Georgia Power, and SCS. The complaint alleged violations of the New Source Review (NSR) provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia and violations of related state laws. The civil action requested penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued to the retail operating companies notices of violation relating to 10 generating facilities, which included the five facilities mentioned previously and the Company's Plants Crist and Scherer. See Note 4 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 violations alleged in its notices of violation and to add the Company, Mississippi Power, and Savannah Electric as defendants.
In August 2000, the U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and granted SCS's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. In March 2001, the court granted the EPA's motion to add Savannah Electric as a defendant, but it denied the motion to add the Company and Mississippi Power based on lack of jurisdiction in Georgia over those companies. As directed by the court, the EPA refiled its amended complaint limiting claims to those brought against Georgia Power and Savannah Electric. In addition, the EPA refiled its claims against Alabama Power in the U.S. District Court for the Northern District of Alabama. These complaints allege violations with respect to eight coal-fired generating facilities in Alabama and Georgia, and they request the same kinds of relief as was requested in the original complaint, i.e. penalties and injunctive relief, including installation of the best available control technology. The EPA has not refiled against the Company, Mississippi Power, or SCS.
The actions against Alabama Power, Georgia Power, and Savannah Electric were stayed in the spring of 2001 during the appeal of a very similar NSR enforcement action against the Tennessee Valley Authority (TVA) before the U.S. Court of Appeals for the Eleventh Circuit. The TVA appeal involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and Savannah Electric. Because the final resolution of the TVA appeal could have
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a significant impact on Alabama Power and Georgia Power, both companies have been involved in that appeal. On June 24, 2003, the Court of Appeals issued its ruling in the TVA case. It found unconstitutional the statutory scheme set forth in the Clean Air Act that allowed the EPA to impose penalties for failing to comply with an administrative compliance order, like the one issued to TVA, without the EPA having to prove the underlying violation. Thus, the Court of Appeals held that the compliance order was of no legal consequence, and TVA was free to ignore it. The court did not however, rule directly on the substantive legal issues about the proper interpretation and application of certain NSR provisions that had been raised in the TVA appeal. On September 16, 2003, the Court of Appeals denied the EPA's request for a rehearing of the decision and on February 13, 2004, the EPA petitioned the U.S. Supreme Court to review the Eleventh Circuit's decision. The actions against Alabama Power, Georgia Power, and Savannah Electric could remain stayed pending this appeal. The EPA also filed a motion to lift the stay in the action against Alabama Power. At this time, no party to the Georgia Power and Savannah Electric action, which was administratively closed two years ago, has asked the court to reopen that case.
Since the inception of the NSR proceedings against Georgia Power, Alabama Power, and Savannah Electric, the EPA has also been proceeding with similar NSR enforcement actions against other utilities, involving many of the same legal issues. In each case, the EPA alleged that the utilities failed to comply with the NSR permitting requirements when performing maintenance and construction activities at coal-burning plants, which activities the utilities considered to be routine or otherwise not subject to NSR. In 2003, district courts addressing these cases issued opinions that reached conflicting conclusions.
In October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act clarifying the scope of the existing Routine Maintenance, Repair, and Replacement exclusion. On December 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit stayed the effectiveness of these revisions pending resolution of related litigation. In January 2004, the Bush Administration announced that it would continue to enforce the existing rules.
The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome in this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly the Company's financial condition if such costs are not recovered through regulated rates.
Personal Injury Litigation
On January 28, 2003, a jury in Escambia County, Florida returned a verdict of $3 million against the Company arising out of an alleged electrical injury sustained by the plaintiff in January 1999 while inside his apartment. This matter is on appeal to Florida's First District Court of Appeal. If this verdict is upheld, there is insurance coverage available to offset a substantial portion of this amount. The ultimate outcome of this matter cannot now be determined, but is not expected to have a material impact on the Company's financial statements.
Right of Way Litigation
Southern Company and certain of its subsidiaries, including the Company, Georgia Power, Mississippi Power, and Southern Telecom (collectively, defendants), have been named as defendants in numerous lawsuits brought by landowners since 2001 regarding the installation and use of fiber optic cable over defendants' rights of way located on the landowners' property. 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 by defendants exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment. The plaintiffs seek compensatory and punitive damages and injunctive relief. With respect to one such lawsuit brought by landowners regarding the installation and use of fiber optic cable over Company rights of way located on the landowners' property, on November 7, 2003, the Second Circuit Court in Gadsden County, Florida, ruled in favor of the plaintiffs on their motion for partial summary judgment concerning liability.
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The question of damages, if any, will be decided at a future trial. In the event of an adverse verdict on damages, the Company could appeal the verdicts on both liability and damages. The Company believes that it has complied with applicable laws and that the plaintiffs' claims are without merit. An adverse outcome in these matters could result in substantial judgments; however, the final outcome of these matters cannot now be determined.
In addition, in late 2001, certain subsidiaries of Southern Company, including the Company, Alabama Power, Georgia Power, Mississippi Power, Savannah Electric, and Southern Telecom (collectively, defendants), 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 the telecommunications company in pending and future right of way litigation. The Company believes that the plaintiff's claims are without merit. 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 Rate Matters
In October 1999, the Office of Public Counsel, the Coalition for Equitable Rates, the Florida Industrial Power Users Group, and the Company jointly filed a petition with the FPSC that included a reduction to retail base rates of $10 million annually and provided for revenues to be shared within set ranges for 1999 through 2002. The Company recorded revenues subject to refund (with interest) of $1.5 million in 2001. No refund was required in 2002. The sharing plan expired on April 21, 2002.
In May 2002, the FPSC approved a retail base rate increase of $53.2 million effective June 7, 2002 primarily related to the commercial operation of Plant Smith Unit 3.
FERC Matters
The Company has obtained FERC approval to sell power to nonaffiliates at market-based prices under specific contracts. Through SCS, as agent, the Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities' applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company's retail operating companies, and found them to be "pivotal suppliers" in their service areas and ordered the implementation of several mitigation measures. SCS, on behalf of the Company and the other retail operating companies, sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. SCS, on behalf of the Company and the other retail operating companies, submitted comments to the FERC in 2002 regarding these issues. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. The Company anticipates that the FERC will address the requests for rehearing in the near future. Regardless of the outcome of the SMA proposal, the FERC retains the ability to modify or withdraw the authorization for any seller to sell at market-based rates, if it determines that the underlying conditions for having such authority are no longer applicable. The final outcome of this matter will depend on the form in which the SMA test and mitigation measures rules may be ultimately adopted and cannot be determined at this time.
4. JOINT OWNERSHIP AGREEMENTS
The Company and Mississippi Power jointly own Plant Daniel Unit No. 1 and Unit No. 2, which together represent capacity of 1,000 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 No. 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.
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At December 31, 2003, the Company's percentage ownership and its investment in these jointly owned facilities were as follows:
Plant Plant Scherer Daniel Unit Unit No. 3 Nos. 1 & 2 (coal) (coal) ----------------------------- (in thousands) Plant In Service $189,502(1) $234,914 Accumulated Depreciation $ 80,631 $122,904 Construction Work in Progress $ 91 $ 815 Ownership 25% 50% - ------------------------------------------------------------------
(1) Includes net plant acquisition adjustment.
5. INCOME TAXES
The Company and the other subsidiaries of Southern Company file a consolidated federal income tax return. In 2002, Southern Company began filing a combined State of Georgia income tax return. Under a joint consolidated income tax 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.
At December 31, 2003, the tax-related regulatory assets to be recovered from customers were $18.3 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, 2003, the tax-related regulatory liabilities to be credited to customers were $26.5 million. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits.
Details of income tax provisions are as follows:
2003 2002 2001 ----------------------------------------- (in thousands) Total provision for income taxes: Federal-- Current $33,085 $24,474 $24,207 Deferred 2,488 7,936 2,568 - -------------------------------------------------------------------- 35,573 32,410 26,775 - -------------------------------------------------------------------- State-- Current 4,585 3,051 3,701 Deferred 719 1,683 826 - -------------------------------------------------------------------- 5,304 4,734 4,527 - -------------------------------------------------------------------- Total $40,877 $37,144 $31,302 ====================================================================
Net cash payments for income taxes related to continuing operations in 2003, 2002, and 2001 were $23.8 million, $34.0 million, and $36.8 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:
2003 2002 ------------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $200,129 $188,879 Other 27,669 28,377 - ------------------------------------------------------------------ Total 227,798 217,256 - ------------------------------------------------------------------ Deferred tax assets: Federal effect of state deferred taxes 9,568 9,421 Postretirement benefits 11,793 10,826 Other 24,347 18,396 - ------------------------------------------------------------------ Total 45,708 38,643 - ------------------------------------------------------------------ Net deferred tax liabilities 182,090 178,613 Less prepaid expense (accrued income taxes), net (6,405) (10,924) - ------------------------------------------------------------------ Accumulated deferred income taxes in the Balance Sheets $175,685 $167,689 ==================================================================
Deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation and amortization in the Statements of Income. Credits amortized in this manner amounted to $1.8 million in 2003, $1.8 million in 2002, and $1.7
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million in 2001. At December 31, 2003, all investment tax credits available to reduce federal income taxes payable had been utilized.
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
2003 2002 2001 ---------------------------- Federal statutory rate 35% 35% 35% State income tax, net of federal deduction 3 3 4 Non-deductible book depreciation 1 1 1 Difference in prior years' deferred and current tax rate (1) (2) (2) Other, net (1) (1) (3) - ---------------------------------------------------------------- Effective income tax rate 37% 36% 35% ================================================================
6. FINANCING
Mandatorily Redeemable Preferred Securities
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 $72.2 million, which constitute substantially all of the assets of these trusts. The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective trusts' payment obligations with respect to these securities. At December 31, 2003, preferred securities of $70 million were outstanding and recognized as liabilities in the Balance Sheets.
Long-Term Debt Due Within One Year
At December 31, 2003, the Company had an improvement fund requirement of $550,000. The first mortgage bond improvement fund requirement amounts to 1 percent of each outstanding series of bonds authenticated under the mortgage indenture prior to January 1 of each year, other than those issued to collateralize pollution control revenue bond obligations. The requirement may be satisfied by depositing cash, reacquiring bonds, or by pledging additional property equal to 1 and 2/3 times the requirement.
The sinking fund requirements of first mortgage bonds were satisfied by certifying property additions in 2003 and 2002. It is anticipated that the 2004 requirement will be satisfied by certifying property additions. Sinking fund requirements and/or maturities through 2008 applicable to long-term debt are as follows: $50.6 million in 2004; $0.6 million in 2005; $37.6 million in 2006; $0.3 million in 2007; and $0.3 million in 2008.
Dividend Restrictions
The Company's first mortgage bond indenture contains various common stock dividend restrictions, which remain in effect as long as the bonds are outstanding. At December 31, 2003, retained earnings of $127 million were restricted against the payment of cash dividends on common stock under the terms of the mortgage indenture.
In accordance with the PUHCA, the Company is also restricted from paying common dividends to the Southern Company from paid-in capital without SEC approval.
Assets Subject to Lien
The Company's mortgage indenture dated as of September 1, 1941, as amended and supplemented, which secures the first mortgage bonds issued by the Company, constitutes a direct first lien on substantially all of the Company's fixed property and franchises.
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 satify obligations of Southern Company or any of its subsidiaries.
Bank Credit Arrangements
At the beginning of 2004, the Company had $56 million of lines of credit with banks subject to renewal each year, all of which remained unused. The $56 million in committed lines of credit provide liquidity support for the Company's commercial paper program and for $4 million of daily variable rate pollution control bonds. In connection with these credit lines, the Company has agreed to pay commitment fees and/or to maintain compensating balances with the banks. The compensating balances, which represent substantially all of the cash of the Company except for daily working funds and like items, are not legally restricted from withdrawal.
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NOTES (continued) Gulf Power Company 2003 Annual Report
Certain credit arrangements contain covenants that limit the level of indebtedness to capitalization to 65 percent, as defined in the agreements. Not meeting these limits would result in an event of default under the credit arrangements. In addition, certain credit arrangements contain cross default provisions to other indebtedness that would trigger an event of default if the borrower 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. Borrowings under unused credit arrangements totaling $20 million would be prohibited if the Company experiences a material adverse change (as defined in such arrangements).
The Company borrows through a commercial paper program that has the liquidity support of committed bank credit arrangements and through an extendible commercial note program. The amount of commercial paper outstanding at December 31, 2003 was $37.7 million. During 2003, the peak amount outstanding for commercial paper was $39.1 million and the average amount outstanding was $12.8 million. The average annual interest rate on commercial paper was 1.2%.
In addition, the Company has bid-loan facilities with five major money center banks that total $50 million, with none committed at December 31, 2003.
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 FPSC. The Company enters into hedges of forward electricity sales.
At December 31, 2003, the fair value of derivative energy contracts was reflected in the financial statements as follows:
Amounts - -------------------------------------------------------------- (in thousands) Regulatory liabilities, net $2,501 Other comprehensive income - Net income 2 - -------------------------------------------------------------- Total fair value $2,503 ==============================================================
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 also enters into derivatives to hedge exposure to interest rate changes. Derivatives related to fixed rate securities are accounted for as fair value hedges. The derivatives are generally structured to match the critical terms of the hedged debt instruments; therefore, no material ineffectiveness has been recorded in earnings.
During 2003, the Company settled interest derivatives at the same time it issued debt and recognized losses totaling $3.3 million. These losses have been deferred in other comprehensive income and will be reclassified to interest expense over the life of the related debt. 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. For the year 2003, approximately $0.2 million of pre-tax losses were reclassified from other comprehensive income to interest expense. For the year 2004, pre-tax losses of approximately $0.3 million are expected to be reclassified from other comprehensive income to interest expense.
7. COMMITMENTS
Construction Program
The Company is engaged in a continuous construction program, the cost of which is currently estimated to total $166 million in 2004, $149 million in 2005, and $108 million in 2006. 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; revised load growth estimates; changes in environmental regulations; changes in FERC rules and transmission regulations; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2003, significant purchase commitments were outstanding in connection with the construction program.
Included in the amounts above, the Company has budgeted $64 million, $31 million, and $4 million in 2004, 2005, and 2006, respectively, for capital
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expenditures related to environmental controls at Plant Crist as part of an agreement with the FDEP to reduce nitrogen oxide emissions. The FPSC authorized the Company to recover the costs related to these environmental projects through the ECRC. 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 are ongoing.
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 combined cycle and combustion turbine generating facilities. 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 the contract.
In general, the LTSA is in effect through two major inspection cycles of the unit. Scheduled payments to GE are made at various intervals based on actual operating hours of the unit. Total payment to GE under this agreement for facilities owned is currently estimated at $84.2 million over approximately 11 years. However, the LTSA contains various cancellation provisions at the option of the Company.
Payments made to GE prior to the performance of any planned inspections are recorded as a prepayments. These amounts are included in prepaid expenses and other assets in the Balance Sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed.
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. Natural gas purchase commitments contain given volumes with prices based on various indices at the time of delivery. Amounts included in the chart below represent estimates based on New York Mercantile future prices at December 31, 2003. Also, the Company has a long-term commitment for the purchase of electricity. Total estimated minimum long-term obligations at December 31, 2003 were as follows:
Natural Purchased Year Gas Fuel Power - ---------------------------------------------------------------- (in millions) 2004 $104 $132 $1 2005 65 77 - 2006 59 78 - 2007 45 78 - 2008 19 18 - 2009 and thereafter 259 - - - ---------------------------------------------------------------- Total commitments $551 $383 $1 ================================================================
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, the other retail operating companies, Southern Power, and Southern Company GAS. Under these agreements, each of the retail operating companies, Southern Power, and Southern Company GAS may be jointly and severally liable. The creditworthiness of Southern Power and Southern Company GAS is currently inferior to the creditworthiness of the retail operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other retail operating companies to insure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power or Southern Company GAS as a contracting party under these agreements.
Operating Leases
The Company has operating lease agreements with various terms and expiration dates. Total operating lease expenses were $2.2 million, $2.1 million, and $1.9 million for 2003, 2002, and 2001, respectively.
At December 31, 2003, estimated minimum rental commitments for noncancelable operating leases were as follows:
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NOTES (continued) Gulf Power Company 2003 Annual Report
Year Amounts ----- ------------------ (in thousands) 2004 $ 1,995 2005 2,100 2006 2,042 2007 2,038 2008 2,037 2009 and thereafter 8,153 ------------------------------------------------------------ Total commitments $18,365 ============================================================
In 1989, the Company and Mississippi Power jointly entered into a twenty-two year operating lease agreement for the use of 495 aluminum railcars. In 1994, a second lease agreement for the use of 250 additional aluminum railcars were entered into for twenty-two years. Both of these leases are for the transportation of coal to Plant Daniel. The Company has the option to purchase the 745 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, as a joint owner of Plant Daniel Units 1 and 2, is responsible for one-half of the lease costs. The lease commitments above include the railcar lease amounts. The lease costs 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 $1.9 million in 2003, $1.9 million in 2002, and $1.9 million in 2001. The annual amounts for 2004 through 2008 are expected to be $1.9 million, $2.0 million, $2.0 million, $2.0 million, and $2.0 million, respectively, and after 2008 are expected to total $8.2 million.
8. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 2003 and 2002 are as follows:
Net Income Operating Operating After Dividends Quarter Ended Revenues Income on Preferred Stock - ---------------------------------------------------------------------- (in thousands) March 2003 $197,838 $32,797 $13,972 June 2003 215,209 40,668 18,785 September 2003 252,889 61,545 32,798 December 2003 211,761 16,890 3,455
March 2002 $160,933 $24,493 $11,717 June 2002 209,987 31,174 13,487 September 2002 245,601 65,661 33,979 December 2002 203,946 24,159 7,853 - ----------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and the timing of rate changes, among other factors.
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MISSISSIPPI POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Mississippi Power Company 2003 Annual Report
The management of Mississippi Power Company (the Company) has prepared -- and is responsible for -- the financial statements and related information included in this report. These statements were prepared in accordance with accounting principles generally accepted in the United States and necessarily include amounts that are based on the best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that the accounting records reflect only authorized transactions of the Company. Limitations exist in any system of internal controls, however, based on recognition that the cost of the system should not exceed its benefits. The Company believes its system of internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's internal accounting controls are evaluated on an ongoing basis by the Company's internal audit staff. The Company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements.
Southern Company's audit committee of its board of directors, composed of four independent directors, provides a broad overview of management's financial reporting and control functions. Additionally, a committee of the Company's board of directors, composed of four outside directors, meets periodically with management, the internal auditors, and the independent public accountants to discuss auditing, internal controls, and compliance matters. The internal auditors and independent public accountants have access to the members of these committees at any time.
Management believes that its policies and procedures provide reasonable assurance that the Company's operations are conducted according to a high standard of business ethics.
In management's opinion, the financial statements present fairly, in all material respects, the financial position, results of operations, and cash flows of the Company in conformity with accounting principles generally accepted in the United States.
/s/Anthony J. Topazi Anthony J. Topazi President and Chief Executive Officer
/s/Michael W. Southern Michael W. Southern Vice President, Treasurer and, Chief Financial Officer
March 1, 2004
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INDEPENDENT AUDITORS' REPORT
Mississippi Power Company:
We have audited the accompanying balance sheets and statements of capitalization of Mississippi Power Company (a wholly owned subsidiary of Southern Company) as of December 31, 2003 and 2002, and the related statements of income, comprehensive income, common stockholder's equity, and cash flows for the years then ended. These financial statements are the responsibility of Mississippi Power Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The financial statements of Mississippi Power Company for the year ended December 31, 2001 were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements and included an explanatory paragraph that described a change in the method of accounting for derivative instruments and hedging activities in their report dated February 13, 2002.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, the financial statements (pages II-218 to II-239) present fairly, in all material respects, the financial position of Mississippi Power Company at December 31, 2003 and 2002, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the financial statements, in 2003 Mississippi Power Company changed its method of accounting for asset retirement obligations.
/s/Deloitte & Touche LLP Atlanta, Georgia March 1, 2004
THE FOLLOWING REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH THE COMPANY'S 2001 ANNUAL REPORT ON FORM 10-K AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP. SEE EXHIBIT 23(e)2 FOR ADDITIONAL INFORMATION.
To Mississippi Power Company:
We have audited the accompanying balance sheets and statements of capitalization of Mississippi Power Company (a Mississippi corporation and a wholly owned subsidiary of Southern Company) as of December 31, 2001 and 2000, and the related statements of income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2001. 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 auditing standards generally accepted in the 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, the financial statements (pages II-160 through II-176) referred to above present fairly, in all material respects, the financial position of Mississippi Power Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
As explained in Note 1 to the financial statements, effective January 1, 2001, Mississippi Power Company changed its method of accounting for derivative instruments and hedging activities.
/s/Arthur Andersen LLP Atlanta, Georgia February 13, 2002
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Mississippi Power Company 2003 Annual Report
OVERVIEW OF EARNINGS AND BUSINESS - --------------------------------- ACTIVITIES - ----------
Earnings
Mississippi Power Company's net income after dividends on preferred stock of $73.5 million in 2003 remained relatively flat from $73.0 million in 2002. However, operating revenues and expenses recorded by the Company in 2003 were unusually high as compared to 2002. An increase of $62 million in other electric revenues resulted from the termination of a contract with a subsidiary of Dynegy, Inc. (Dynegy), the income effect of which was offset by the recording of a $60 million expense related to the establishment of a regulatory liability in connection with an interim accounting order issued by the Mississippi Public Service Commission (MPSC) related to the Plant Daniel capacity expense. See Note 3 to the financial statements under "Contract Termination" and "Retail Regulatory Filing" for additional information. Excluding these two items, operating revenues and operating expense were lower in 2003 than in 2002 primarily due to decreased fuel revenues and lower fuel and purchased power costs. Also, milder weather in 2003 caused kilowatt-hour sales to be slightly lower than in 2002. The 2002 increase of $9.1 million in net income as compared to the prior year was primarily attributable to the retail and wholesale rate increases in late 2001 and early 2002, respectively, and lower interest expense. The increase in net income of $8.9 million for 2001 was due primarily to the commercial operation of Plant Daniel Units 3 and 4 and lower interest costs.
Business Activities
The Company currently 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.
Several factors affect the opportunities, challenges, and risk of selling electricity. These factors include the Company's ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stricter environmental standards. 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 service area.
RESULTS OF OPERATIONS - ---------------------
A condensed income statement is as follows:
Increase (Decrease) Amount From Prior Year ------------------------------------------ 2003 2003 2002 2001 - ------------------------------------------------------------------- (in thousands) Operating revenues $869,924 $ 45,759 $ 28,100 $108,463 - ------------------------------------------------------------------- Fuel 229,251 (53,142) 4,447 86,819 Purchased power 93,197 41,864 (43,911) (11,895) Other operation and maintenance 300,118 68,105 41,015 23,193 Depreciation and amortization 55,700 (1,938) 3,561 3,802 Taxes other than income taxes 53,991 (1,527) 10,552 (3,720) - ------------------------------------------------------------------- Total operating expenses 732,257 53,362 15,664 98,199 - ------------------------------------------------------------------ Operating income 137,667 (7,603) 12,436 10,264 Other income (expense), net (18,853) 7,525 2,036 4,828 Less -- Income taxes 45,315 (564) 5,346 6,177 - ------------------------------------------------------------------- Net Income $ 73,499 $ 486 $ 9,126 $ 8,915 ===================================================================
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Revenues
Details of the Company's operating revenues in 2003 and the prior two years are as follows:
Amount - -------------------------------------------------------------- 2003 2002 2001 (in thousands) Retail -- prior year $536,827 $489,153 $498,551 Change in -- Base rates - 38,143 - Sales growth 1,175 566 (1,048) Weather (1,542) 3,533 (1,953) Fuel cost recovery (20,159) 5,432 (6,397) and other - -------------------------------------------------------------- Retail -- current year 516,301 536,827 489,153 - -------------------------------------------------------------- Sales for resale -- Non-affiliates 249,986 224,275 204,623 Affiliates 26,723 46,314 85,652 - -------------------------------------------------------------- Total sales for resale 276,709 270,589 290,275 - -------------------------------------------------------------- Contract termination 62,111 - - Other electric operating revenues 14,803 16,749 16,637 - -------------------------------------------------------------- Total electric operating revenues $869,924 $824,165 $796,065 ============================================================= Percent change 5.6% 3.5% 15.8% - -------------------------------------------------------------
Total retail revenues for 2003 decreased approximately 3.8 percent when compared to 2002 as a result of decreased fuel revenues and to the lesser extent decreases in kilowatt-hour energy sales due to milder than normal weather in the Company's service area and the sluggish economy. Retail revenues for 2002 increased approximately 9.7 percent when compared to 2001, primarily due to a retail rate increase which took effect in January 2002 and, to a lesser extent, higher kilowatt-hour energy sales resulting from colder winter weather. See Note 3 to the financial statements under "2001 Retail Rate Case" for additional information. Retail revenues for 2001 reflected a 1.9 percent decrease from 2000 due to lower energy sales to residential, commercial, and industrial customers as a result of mild weather and a slowdown in manufacturing activity in the Company's service territory.
Fuel revenues generally represent the direct recovery of fuel expense including purchased power. Therefore, changes in recoverable fuel expenses are offset with corresponding changes in fuel revenues and have no effect on net income. During 2003, the fuel cost recovery and other revenues decreased $20 million compared to 2002 due to a reduction in rates that became effective in 2003.
Sales for resale to non-affiliates are influenced by the non-affiliate utilities' own customer demand, plant availability, and cost of predominant fuels. Included in sales for resale to non-affiliates are revenues from rural electric cooperative associations and municipalities located in southeastern Mississippi. Sales to these utilities remained relatively flat in 2003 compared to 2002, increased 8.0 percent in 2002, and decreased 3.7 percent in 2001, with the related revenues increasing 1.6 percent, increasing 19.8 percent, and decreasing 2.4 percent, respectively. The customer demand experienced by these utilities is determined by factors very similar to those of the Company. Total revenues from sales for resale to non-affiliates increased in 2003 as a result of increases in average sales price per kilowatt-hour and increased kilowatt-hour sales to wholesale non-affiliate customers. Revenues from sales for resale to non-affiliates increased in 2002 and 2001, primarily as the result of a new power sales contract that began in June 2001, as well as colder winter months during 2002.
In May 2003, the Company entered into an agreement with Dynegy that resolved and terminated in 2003 all outstanding matters related to capacity sales contracts with subsidiaries of Dynegy. The termination payment from Dynegy resulted in an increase in other electric revenues of $62 million for the year 2003. See Note 3 to the financial statements under "Contract Termination" for additional information.
Energy Sales
Energy sales to affiliated companies within the Southern Company electric system vary from year to year depending on demand and the availability and cost of generating resources at each company. These sales do not have a significant impact on earnings since the energy is generally sold at marginal cost.
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Kilowatt-hour (KWH) sales for 2003 and percent change by year were as follows:
Percent Change KWH ----------------------------- 2003 2003 2002 2001 -------------------------------------------------------------- (in millions) Residential 2,256 (1.9)% 6.3% (5.4)% Commercial 2,914 0.4 2.1 (1.5) Industrial 4,111 (1.2) (2.7) (2.3) Other 40 - - (0.3) ----------- Total retail 9,321 (0.9) 0.1 (2.8) Sales for Resale Non-Affiliated 5,875 9.2 7.4 36.4 Affiliated 709 (55.3) (46.3) 552.3 ----------- Total 15,905 (2.8) (5.3) 26.0 ==============================================================
Total retail kilowatt-hour sales decreased in 2003 as the result of milder weather in 2003 when compared to 2002. Total retail kilowatt-hour sales increased slightly in 2002 due to colder than average winter weather, which primarily affected residential sales. In addition, commercial sales increased 2.1 percent in 2001 due primarily to growth in the health, education, and retail sales areas. Industrial sales fell 2.7 percent in 2002 due to an economic downturn in the Company's service area. In 2001, residential sales decreased 5.4 percent due to unusually mild weather in the Company's service area. The commercial sales and industrial sales in 2001 decreased 1.5 percent and 2.3 percent, respectively, due to an economic slowdown in the Company's service area. Kilowatt-hour sales for non-affiliated sales for resale increased in 2002 and 2001 due to the increased demand from these customers and the commercial operation of Plant Daniel Units 3 and 4 in May 2001.
The Company anticipates relatively slow growth over the next five years due to a slow recovery from the national and area economic downturn and a maturing of the gaming and tourism industry. Retail sales are expected to grow at an annual average rate of approximately 1% through 2008, with increases expected in the local, state, and federal government sectors, as well as increases in shipbuilding, education, and health care.
Expenses
Total operating expenses were $732 million in 2003, which reflects an increase of 7.9 percent over 2002. The increase in 2003 is due primarily to $60 million in Plant Daniel capacity expense recorded in connection with an interim accounting order from the MPSC. See Note 3 to the financial statements under "Retail Regulatory Filing" for further information. In 2002, total operating expenses were $679 million, reflecting an increase of 2.4 percent over the prior year. The increase was due primarily to increases in maintenance expense due to planned outages at Plant Watson and Plant Daniel and a full year of rental expense for Plant Daniel Units 3 and 4, as well as a slight increase in fuel expense. In 2001, total operating expenses increased by 17.4 percent over the prior year due primarily to the commercial operation and related lease of Plant Daniel Units 3 and 4 beginning in May 2001. See Note 7 to the financial statements under "Operating Leases -- Plant Daniel Combined Cycle Generating Units" for additional information.
Fuel costs are the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of fossil generating units. The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated and the average cost of purchased power were as follows:
2003 2002 2001 - --------------------------------------------------------------- Total generation (millions of kilowatt hours) 12,850 15,079 15,770 Sources of generation (percent) -- Coal 74 57 59 Gas 26 43 41 Average cost of fuel per net kilowatt-hour generated (cents) -- 1.95 2.03 1.89 Average cost of purchased power per kilowatt-hour (cents) -- 2.55 2.61 4.27 - ---------------------------------------------------------------
Fuel expense for 2003 decreased 18.8 percent due to decreased generation and lower average cost of fuel. Fuel expense for 2002 and 2001 increased 1.6 percent and 45.4 percent, respectively. The increase for 2002 was due to a fuel hedging loss, which is approved for recovery through the Energy Cost Management Plan (ECM), authorized by the MPSC. The 2001 increase was due to increased
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generation in conjunction with the initial operation of Plant Daniel Units 3 and 4 and a higher average cost of fuel.
In 2003, purchased power expense increased $41.9 million or 81.6 percent. The increase is primarily due to an increase in purchased power expense from affiliate companies. Those purchases were more economical than self generation due to the increase in the cost of natural gas in 2003. Energy purchases vary from year to year depending on demand and the availability and cost of generating resources at the Company. These expenses do not have a significant impact on earnings since the energy purchases are generally offset by energy revenues through the Company's retail and wholesale fuel cost recovery clauses. In 2002, purchased power expense decreased 46.1 percent when compared to 2001. This decrease resulted from both lower prices and lower purchase requirements, primarily due to the commercial operation of Plant Daniel Units 3 and 4 beginning in May 2001. In 2001, purchased power expense decreased 11.1 percent primarily due to the commercial operation of Plant Daniel Units 3 and 4 and the expiration of non-affiliated purchase power contracts in 2000.
Other operation expense increased $71.7 million or 45.3 percent in 2003, primarily due to approximately $11 million incurred to restructure the lease agreement for the combined cycle generating units at Plant Daniel and $60 million in expense recorded in connection with the recognition of a regulatory liability following an interim accounting order from the MPSC related to Plant Daniel capacity expense. See Notes 3 and 7 to the financial statements under "Retail Regulatory Filing" for further information regarding the Plant Daniel capacity. Also, see "Financial Condition and Liquidity -- Off-Balance Sheet Financing Arrangements" herein and Note 7 to the financial statements under "Operating Leases -- Plant Daniel Combined Cycle Generating Units" for further information regarding the Plant Daniel lease. In 2002, other operation expense increased 17.4 percent primarily due to lease payments associated with the commercial operation of Plant Daniel Units 3 and 4 and higher labor related expenses. In 2001, other operation expense increased 17.2 percent primarily due to an increase in other production expenses resulting from the commercial operation of Plant Daniel Units 3 and 4.
Maintenance expense decreased 4.9 percent in 2003 primarily due to a decrease in the long term service agreement expense of $5 million. The decrease was attributable to the decrease in fired operating hours at Plant Daniel Units 3 and 4 of approximately 50 percent. In 2002, maintenance expense increased 31.2 percent primarily due to scheduled maintenance performed at Plant Watson and Plant Daniel, while maintenance expense in 2001 increased 6.5 percent as a result of the commercial operation of Plant Daniel Units 3 and 4.
In 2003, depreciation and amortization expense decreased $1.9 million compared to 2002 primarily due to a reduction in the amortization of environmental expenses based on the Company's Environmental Compliance Overview Plan (ECO Plan) filing with the MPSC. In 2002 and 2001, depreciation and amortization expense increased 6.6 percent and 7.6 percent, respectively, due to a growth in plant investment and amortization of the Company's regulatory asset related to the recovery of environmental compliance costs. See Note 3 to the financial statements under "Environmental Compliance Overview Plan" for further information.
Taxes other than income taxes decreased 2.8 percent in 2003 primarily due to lower property taxes in 2003. Taxes other than income taxes increased 23.5 percent in 2002 due to additional property taxes related to Plant Daniel Units 3 and 4 and higher municipal franchise taxes. These taxes decreased 7.6 percent in 2001 due to reductions in certain ad valorem tax rates. The decrease in total other income and expense is due to interest on long-term debt decreasing in 2003, 2002, and 2001 as a result of lower interest rates on debt outstanding and lower principal amount of debt outstanding.
Effects of Inflation
The Company is subject to rate regulation that is based on the recovery of historical costs. In addition, the income tax laws are also based on historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that 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 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
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that arises through financing facilities with fixed-money obligations, such as long-term debt 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 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. These factors affect the opportunities, challenges, and risk of the Company's business of selling electricity. These factors include the Company's ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stricter environmental standards. 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.
Industry Restructuring
The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in southeastern Mississippi and wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the MPSC under cost-based regulatory principles. The Federal Energy Regulatory Commission (FERC) regulates the Company's wholesale rate schedules, wholesale power sales contracts, and wholesale transmission services.
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 Policy Act of 1992 (Energy Act). The Energy Act allowed independent power producers to access a utility's transmission network and sell electricity to other utilities.
Although the Energy Act does not provide for retail customer access, it was a major catalyst for the restructuring and consolidation that took place within the utility industry. Numerous federal and state initiatives that promote wholesale and retail competition are in varying stages. Among other things, these initiatives allow retail customers in some states to choose their electricity provider. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While various restructuring and competition initiatives have been discussed in Mississippi, none have been enacted.
In May 2000, the MPSC ordered that its docket reviewing restructuring of the electric industry in the State of Mississippi be suspended. The MPSC found that retail competition may not be in the public interest at this time and ordered that no further formal hearings would be held on the subject. It also found that the current regulatory structure produced reliable low cost power and "should not be changed without clear and convincing demonstration that change would be in the public interest." The MPSC will continue to monitor retail and wholesale restructuring activities throughout the United States and reserves its right to order further formal hearings on the matter should new evidence demonstrate that retail competition would be in the public interest and all customers could receive a reduction in the total cost of their electric service. If the MPSC decides to hold future restructuring hearings on this matter, enactment could require numerous issues to be resolved, including recovery of any stranded investments, full cost recovery of energy produced and other issues related to the energy crisis that occurred in California, as well as the August 2003 power outage in the Northeast.
Since 2001, merchant energy companies and traditional electric utilities with significant energy marketing and trading activities have come under severe financial pressures. Many of these companies have completely exited or drastically reduced all energy marketing and trading activities and sold foreign and domestic electric infrastructure assets. The Company has not experienced any material adverse financial impact regarding its limited energy trading operations through Southern Company Services (SCS).
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Continuing to be a low-cost producer could provide significant opportunities to increase the size and profitability in markets that evolve with changing regulation and competition. Conversely, future regulatory changes could adversely affect the Company's growth, and if the Company does not remain a low-cost producer and provide quality service, then the Company's energy sales growth could be limited, and this could significantly erode earnings.
Environmental Matters
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action against Alabama Power, Georgia Power, and SCS. The complaint alleged violations of the New Source Review (NSR) provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. The civil action requested penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued to the retail operating companies notices of violation relating to 10 generating facilities, which include the five facilities mentioned previously and the Company's Plants Watson and Greene County. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notices of violation and to add Gulf Power, the Company, and Savannah Electric as defendants. However, in March 2001, the court denied the motion with respect to the Company and Gulf Power based on lack of jurisdiction and the EPA has not refiled. See Note 3 to the financial statements under "New Source Review Actions" for additional information.
In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. The December 2002 revisions included changes to the regulatory exclusions and the methods of calculating emissions increases. The October 2003 regulations clarified the scope of the existing Routine Maintenance, Repair, and Replacement exclusion. A coalition of states and environmental organizations filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. On December 24, 2003, the court of appeals granted a stay of the October 2003 revisions pending its review of the rules and ordered that its review be conducted on an expedited basis. In January 2004, the Bush Administration announced that it would continue to enforce the existing rules until the courts resolve legal challenges to the EPA's revised NSR regulations. In any event, the final regulations must be adopted by the State of Mississippi in order to apply to the Company's facilities. The effect of these final regulations and the related legal challenges cannot be determined at this time.
The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
Environmental Statutes and Regulations
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. Compliance with these environmental requirements will involve significant costs - -- both capital and operating -- a major portion of which is expected to be recovered through existing ratemaking provisions, including the Company's ECO Plan. The ECO Plan is designed to allow recovery of costs of compliance with the Clean Air Act, as well as other environmental statutes and regulations. The MPSC reviews environmental projects and the Company's environmental policy through the ECO Plan. Under the ECO Plan, any increase in the annual revenue requirement is limited to two percent of retail revenues. The Company's management believes that the ECO Plan provides for recovery of the Clean Air Act costs; however, there can be no assurance that all Clean Air Act costs will be recovered. See Note 3 to the financial statements under "Environmental Compliance Overview
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Plan" for additional information. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under "Capital Requirements and Contractual Obligations."
Compliance with the federal Clean Air Act and resulting regulations has been, and will continue to be a significant focus for the Company. The Title IV acid rain provisions of the Clean Air Act, for example, required significant reductions in sulfur dioxide and nitrogen oxide emissions. Title IV compliance was effective in 2000 and associated construction expenditures totaled approximately $65 million.
In September 1998, the EPA issued regional nitrogen oxide reduction rules to the states for implementation. The final rules require compliance by May 31, 2003 for 19 states, not including Mississippi. However, the Company is affected by this rule through its forty percent ownership interest in Greene County Steam Plant in Alabama.
In July 1997, the EPA revised the national ambient air quality standards for ozone and particulate matter. These revisions made the standards significantly more stringent. In the subsequent litigation of these standards, the U.S. Supreme Court found the EPA's implementation program for the new eight-hour ozone standard unlawful and remanded it to the EPA for further rulemaking. During 2003, the EPA proposed implementation rules designed to address the court's concerns. The EPA plans to designate areas as attainment or nonattainment with the new eight-hour ozone standard in April 2004 and with the new fine particulate matter standard by the end of 2004. These designations will be based on air quality data for 2001 through 2003. Based on the most recent air monitoring data, it is anticipated that all counties in the Company's service area will initially be in attainment with both of these standards. However, the impact of any new standards will depend on the development and implementation of applicable regulations and cannot be determined at this time.
In January 2004, the EPA issued a proposed Interstate Air Quality Rule to address interstate transport of ozone and fine particles. This proposed rule would require additional year-round sulfur dioxide and nitrogen oxide emission reductions from power plants in the eastern United States in two phases - in 2010 and 2015. The EPA currently plans to finalize this rule by 2005. If finalized, the rule could modify or supplant other state implementation plan (SIP) requirements for attainment of the fine particulate matter standard and the eight-hour ozone standard. The impact of this rule on the Company will depend upon the specific requirements of the final rule and cannot be determined at this time.
Further reductions in sulfur dioxide and nitrogen oxides could also be required under the EPA's Regional Haze rules. The Regional Haze rules require states to establish Best Available Retrofit Technology (BART) standards for certain sources that contribute to regional haze. The Company has two plants that could be subject to these rules. The EPA Regional Haze program calls for the State of Mississippi to submit SIPs that contain emission reduction strategies for achieving progress toward the visibility improvement goal. The State of Mississippi is on schedule to accomplish this by December 2007. The SIPs must contain emission reduction strategies for implementing BART and achieving progress toward the Clean Air Act's visibility improvement goal. In 2002, however, the U.S. Court of Appeals for the District of Columbia Circuit vacated and remanded the BART provisions of the federal Regional Haze rules to the EPA for further rulemaking. The EPA has entered into an agreement that requires proposed revised rules in April 2004 and final rules in 2005. Because new BART rules have not been developed and state visibility assessments for progress are only beginning, it is not possible to determine the effect of these rules on the Company at this time.
The EPA's Compliance Assurance Monitoring (CAM) regulations under Title V of the Clean Air Act require that monitoring be performed to ensure compliance with emissions limitations on an ongoing basis. In 2004 and 2005, the Plant Watson and Plant Daniel coal fired units will likely become subject to CAM requirements. The Company is in the process of developing CAM plans for Plant Daniel. The Company's CAM plans for Plant Watson are awaiting approval by the Mississippi Department of Environmental Quality (MDEQ). Due to the CAM plans not yet being approved, the Company cannot determine the ultimate costs associated with implementation of the CAM regulations. Actual ongoing monitoring costs are expensed as incurred and are not material for any year presented.
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In January 2004, the EPA issued proposed rules regulating mercury emissions from electric utility boilers. The proposal solicits comments on two possible approaches for the new regulations - a Maximum Achievable Control Technology approach and a cap-and-trade approach. Either approach would require significant reductions in mercury emissions from company facilities. The regulations are scheduled to be finalized by the end of 2004, and compliance could be required as early as 2007. Because the regulations have not been finalized, the impact on the Company cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent emissions limitations on power plants have been proposed by Congress. Three of these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2003, and the Clean Air Planning Act of 2003, propose to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills also propose to limit emissions of carbon dioxide. The cost impacts of such legislation would depend upon the specific requirements enacted and cannot be determined at this time.
Domestic efforts to limit greenhouse gas emissions have been spurred by international discussions surrounding the Framework Convention on Climate Change and specifically the Kyoto Protocol, which proposes international constraints on the emissions of greenhouse gases. The Bush Administration does not support U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation and has instead announced a new voluntary climate initiative, known as Climate VISION, which seeks an 18 percent reduction by 2012 in the rate of greenhouse gas emissions relative to the dollar value of the U.S. economy. The Company is involved in a voluntary electric utility industry sector climate change initiative in partnership with the government. The electric utility sector has pledged to reduce its greenhouse gas intensity 3 percent to 5 percent over the next decade and is in the process of developing a memorandum of understanding with the Department of Energy (DOE) to cover this voluntary program.
The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur costs to clean up properties. However, such costs are expected to be recovered through the ECO Plan. The Company conducts studies to determine the extent of any required clean up and has recognized in the financial statements the costs for clean up of known sites. Should remediation be determined to be probable, reasonable estimates of costs to clean up such sites are developed and recognized in the financial statements.
Under the Clean Water Act, the EPA has been developing new rules aimed at reducing impingement and entrainment of fish and fish larvae at power plant's cooling water intake structures. On February 16, 2004, the EPA finalized these rules. These rules will require biological studies, and perhaps, retrofits to some intake structures at existing power plants. The impact of these new rules will depend on the results of studies and analyses performed as part of the rules' implementation.
In addition, under the Clean Water Act, the EPA and the MDEQ are developing total maximum daily loads (TMDLs) for certain impaired waters. Establishment of maximum loads by the EPA or state agencies may result in lowering permit limits for various pollutants and a requirement to take additional measures to control non-point source pollution (e.g., storm water runoff) at facilities discharging into waters for which TMDLs are established. Because the effect on the Company will depend on the actual TMDLs and permit limitations established by the implementing agency, it is not possible to determine the effect on the Company at this time.
Several major pieces of environmental legislation are periodically considered for reauthorization or amendment by Congress. These 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 possible additional federal or state legislation or regulations related to global climate change, electromagnetic fields, or other environmental and health concerns could also significantly affect the Company. The impact of any new legislation, changes to existing legislation, or environmental regulations could affect many areas of the Company's operations.
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The full impact of any such changes, however, cannot be determined at this time.
FERC Matters
Transmission
In December 1999, the FERC issued its final rule (Order 2000) on Regional Transmission Organizations (RTOs). Order 2000 encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Southern Company and its retail operating companies, including the Company, worked with a number of utilities in the Southeast to develop a for-profit RTO known as SeTrans. In 2002, the sponsors of SeTrans established a Stakeholder Advisory Committee to provide input into the development of the RTO from other sectors of the electric industry, as well as consumers. During the development of SeTrans, state regulatory authorities expressed concern over certain aspects of the FERC's policies regarding RTOs. In December 2003, the SeTrans sponsors announced that they would suspend work on SeTrans because the regulated utility participants, including Southern Company's retail operating companies, had determined that it was highly unlikely to obtain support of both federal and state regulatory authorities. Any impact of the FERC's rule on the Company will depend on the regulatory reaction to the suspension of SeTrans and future developments, which cannot now be determined.
In July 2002, the FERC issued a notice of proposed rulemaking regarding open access transmission service and standard electricity market design. The proposal, if adopted, would among other things: (1) require transmission assets of jurisdictional utilities to be operated by an independent entity; (2) establish a standard market design; (3) establish a single type of transmission service that applies to all customers; (4) assert jurisdiction over the transmission component of bundled retail service; (5) establish a generation reserve margin; (6) establish bid caps for day ahead and spot energy markets; and (7) revise the FERC policy on the pricing of transmission expansions. Comments on the proposal were submitted by many interested parties, including Southern Company, and the FERC has indicated that it has revised certain aspects of the proposal in response to public comments. Proposed energy legislation would prohibit the FERC from issuing the final rule before October 31, 2006, and from making any final rule effective before December 31, 2006. That legislation has been approved by the House of Representatives but remains pending before the Senate. Passage of the legislation now appears in doubt. It is uncertain whether in the absence of legislation the FERC will move forward with any part or all of the proposed rule. Any impact of this proposal on the Company will depend on the form in which the final rule may be ultimately adopted. However, the Company's financial statements could be adversely affected by changes in the transmission regulatory structure in its regional power market.
Market-Based Rate Authority
The Company has obtained FERC approval to sell power to nonaffiliates at market-based prices under specific contracts. Through SCS, as agent, the Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities' applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company's retail operating companies, and found them and others to be "pivotal suppliers" in their service areas and ordered the implementation of several mitigation measures. SCS, on behalf of the Company and the other retail operating companies, sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. SCS, on behalf of the Company and the other retail operating companies, submitted comments to the FERC in 2002 regarding these issues. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. The Company anticipates that the FERC will address the requests for rehearing in the near future. Regardless of the outcome of the SMA proposal, the FERC retains the ability to modify or withdraw the authorization for any seller to sell at market-based rates if it determines that the underlying conditions for having such authority are no longer applicable. The final outcome of this matter will depend on the form in which the SMA test and mitigation measures rules may be ultimately adopted and cannot be determined at this time.
Wholesale Customer Settlement Agreement
In February 2002, the Company reached a settlement agreement with certain of its wholesale customers to increase its wholesale tariff rates effective June 1,
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2002. The FERC accepted the settlement agreement and placed the new tariff rates in effect without modification. The settlement agreement resulted in an annual increase in revenues of approximately $10.5 million, the adoption of an ECM provision, and the cost allocation of Plant Daniel Units 3 and 4, similar to the plans approved by the Company's retail jurisdiction.
Other Matters
In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash pension income, before tax, of approximately $1.7 million, $2.5 million, and $3.2 million in 2003, 2002, and 2001, respectively. Future pension income is dependent on several factors including trust earnings and changes to the plan. The decline in pension income is expected to continue and become an expense as early as 2006. Postretirement benefit costs for the Company were $4 million, $3.7 million, and $3.3 million in 2003, 2002, and 2001, respectively and are expected to continue to trend upward. A portion of pension income and postretirement benefit costs is capitalized based on construction-related labor charges. Pension income or expense and postretirement benefit costs are a component of 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.
On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act). The Medicare Act introduces a prescription drug benefit for Medicare-eligible retirees starting in 2006, as well as a federal subsidy to plan sponsors like the Company that provide prescription drug benefits. In accordance with FASB Staff Position No. 106-1, the Company has elected to defer recognizing the effects of the Medicare Act for its postretirement plans under FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other than Pension, until authoritative guidance on accounting for the federal subsidy is issued or until a significant event occurs that would require remeasurement of the plans' assets and obligations. The Company anticipates that the benefits it pays after 2006 will be lower as a result of the Medicare Act; however, the retiree medical obligations and costs reported in Note 2 to the financial statements do not reflect these changes. The final accounting guidance could require changes to previously reported information.
On May 21, 2003, the Company entered into an agreement with Dynegy that resolved and terminated in 2003 all outstanding matters related to a capacity sales contract with a subsidiary of Dynegy. The termination payments from Dynegy resulted in a one-time gain to the Company of approximately $38 million after tax.
On December 5, 2003, the Company filed a request with the MPSC to include 266 megawatts of Plant Daniel Units 3 and 4 generating capacity in jurisdictional cost of service. In addition, the Company proposed to modify certain provisions of its Performance Evaluation Plan (PEP), the mechanism used for evaluating the Company's retail rate levels. The proposed changes include (1) the use of a forward-looking, rather than a historical, test year, (2) adjustments to the performance indicator mechanism, and, (3) an annual, rather than semi-annual, evaluation period. The Company expects the MPSC to make a decision on its proposal during the second quarter of 2004. See Note 3 to the financial statements under "Retail Regulatory Filing" and "2001 Retail Rate Case" for additional information.
In December 2001, the MPSC approved an increase in the Company's annual retail rate revenues of approximately $39 million, effective January 2002. Additionally, the MPSC ordered the Company to reactivate semi-annual evaluations under the PEP, beginning with the 12-month period ending December 31, 2002. In May 2002, the MPSC issued an order adopting new return on equity models to be used in the PEP process. The new models are very similar to those that established the rate increase authorized in December 2001 and were incorporated into the PEP evaluation filing for the period ending December 31, 2002. See Note 3 to the financial statements under "Retail Regulatory Filing" for additional information.
The Company is involved in various matters being litigated and regulatory matters that could affect future earnings. See Note 3 to the financial statements for information regarding material issues.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2003 Annual Report
ACCOUNTING POLICIES - -------------------
Application of Critical Accounting Policies and Estimates
The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has discussed the development and selection of the critical accounting policies and estimates described below with the Controls and Compliance Committee of the Company's Board of Directors and the Audit Committee of Southern Company's Board of Directors.
Electric Utility Regulation
The Company is subject to retail regulation by the MSPC 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. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of Statement No. 71 has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and post-retirement 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. However, adverse legislation and 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" 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: o 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. o Changes in existing income tax regulations or changes in Internal Revenue Service interpretations of existing regulations. o 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. o Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant. o Resolution or progression of existing matters through the legislative process, through the court systems, or through the EPA.
Plant Daniel Capacity
As discussed in Note 3 to the financial statements under "Retail Regulatory Filing," the Company requested and received an interim accounting order from the
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2003 Annual Report
MPSC on December 16, 2003. The order directed the Company to expense and record in 2003 a regulatory liability of $60.3 million pending the conclusion of the MPSC's evaluation of the Company's request to include an additional 266 megawatts of Plant Daniel Units 3 and 4 generating capacity in jurisdictional cost of service. The MPSC is not expected to complete its evaluation and issue a final order until the second quarter of 2004. Management believes that the interim accounting order represents a probable liability and that recognition of the expense in 2003 is appropriate. However, if the MPSC ultimately refuses the Company's request, the regulatory liability will be required to be reversed.
Plant Daniel Operating Lease
As discussed in Note 7 to the financial statements under "Operating Leases," the Company entered into a lease for a 1,064 megawatt natural gas combined cycle facility at Plant Daniel (Facility) with 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 on the Company's 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: o Fair market value of the Facility at lease inception. o The Company's incremental borrowing rate. o Timing of debt payments and the related amortization of the initial acquisition cost during the initial lease term. o Residual value of the Facility at the end of the lease term. o Estimated economic life of the Facility. o Juniper's status as a voting interest entity.
The determination of operating lease treatment is made at the inception of the lease agreement and is not subject to change unless subsequent changes are made to the agreement. However, in accordance with FASB Interpretation No. 46, Consolidation of Variable Interest Entities, 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 $34 million annually, rather than annual lease expense of approximately $26 million.
New Accounting Standards
Asset Retirement Obligations
Prior to January 2003, the Company accrued for the ultimate cost of retiring most long-lived assets over the life of the related asset through depreciation expense. FASB Statement No. 143, Accounting for Asset Retirement Obligations, established new accounting and reporting standards for legal obligations associated with the ultimate cost of retiring long-lived assets. 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. Additionally, non-regulated companies are no longer permitted to continue accruing future retirement costs for long-lived assets that they do not have a legal obligation to retire. For more information regarding the impact of adopting this standard effective January 1, 2003, see Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal."
Derivative Instruments
FASB Statement No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, which further amends and clarifies the accounting and reporting for derivative instruments, became effective generally for financial instruments entered into or modified after June 30, 2003. Current interpretations of Statement No. 149 indicate that certain electricity forward transactions subject to unplanned netting -- including those typically referred to as "book outs" -- may only qualify as cash flow hedges if an entity can demonstrate that physical delivery or receipt of power occurred. The Company's forward electricity contracts continue to be exempt from fair value accounting requirements or to qualify as cash flow hedges, with the related gains and losses deferred in other comprehensive income. The implementation of Statement No. 149 did not have a material effect on the Company's financial statements.
In July 2003, the Emerging Issues Task Force (EITF) of FASB issued EITF No. 03-11, which became effective on October 1, 2003. The standard addresses the
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2003 Annual Report
reporting of realized gains and losses on derivative instruments and is being interpreted to require book outs to be recorded on a net basis in operating revenues. Adoption of this standard did not have a material impact on the Company's financial statements.
Variable Interest Entities
FASB Interpretation No. 46, Consolidation of Variable Interest Entities, which was originally issued in January 2003, requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. The Company's previous interest in a variable interest entity related to the lease arrangement for certain facilities at Plant Daniel was restructured prior to the original effective date of July 1, 2003, and is no longer subject to Interpretation No. 46. See Note 7 to the financial statements under "Operating Leases -- Plant Daniel Combined Cycle Generating Units" for additional information. In December 2003, the FASB revised Interpretation No. 46 and deferred the effective date until March 31, 2004, for interests held in variable interest entities other than special purpose entities.
Current analysis indicates that the trust established by the Company to issue preferred securities is a variable interest entity under Interpretation No. 46, and that the Company is not the primary beneficiary of this trust. If this conclusion is finalized, effective March 31, 2004, the trust assets and liabilities -- including the preferred securities issued by the trust -- will be deconsolidated. The investments in the trust and the loans from the trust to the Company will be reflected as equity method investments and as long-term notes payable to affiliates, respectively, on the Balance Sheets. Based on December 31, 2003 values, this treatment would result in an increase of approximately $1 million to both total assets and total liabilities. See Note 6 to the financial statements under "Mandatorily Redeemable Preferred Securities" for additional information.
Liabilities and Equity
In May 2003, the FASB issued Statement No. 150, Accounting or Certain Financial Instruments with Characteristics of Both Liabilities and Equity, which requires classification of certain financial instruments within its scope, including shares that are mandatorily redeemable, as liabilities. Statement No. 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise on July 1, 2003. In accordance with Statement No. 150, mandatorily redeemable preferred securities are reflected on the Balance Sheets as liabilities. The adoption of Statement No. 150 had no impact on the Statements of Income and Cash Flows.
FINANCIAL CONDITION AND LIQUIDITY - ---------------------------------
Overview
During 2003, the Company operated at high levels of reliability while achieving industry-leading customer satisfaction levels and continuing to have retail prices below the national average.
The Company's ratio of common equity to total capitalization, excluding long-term debt due within one year, increased from 62.5 percent in 2002 to 66.4 percent at December 31, 2003.
The principal changes in the Company's financial condition during 2003 were the addition of approximately $69.3 million to utility plant and the reduction of long-term debt. See the Statements of Cash Flows for additional information.
Sources of Capital
The Company plans to obtain the funds required for construction and other purposes, including compliance with environmental regulations, from sources similar to those used in the past. These sources were primarily the issuance of unsecured debt and preferred securities, in addition to pollution control revenue bonds issued for the Company's benefit by public authorities. However, the type and timing of any future financings--if needed--will depend on market conditions and regulatory approval.
The Company has no restrictions on the amounts of unsecured indebtedness it may incur. However, the Company is required to meet certain coverage requirements specified in its mortgage indenture and corporate charter to issue new first mortgage bonds and preferred stock. The Company's coverage ratios are high enough to permit, at present interest rate levels, any foreseeable security
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2003 Annual Report
sales. The amount of securities which the Company will be permitted to issue in the future will depend upon market conditions and other factors prevailing at that time.
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. In accordance with the Public Utility Holding Company Act, most loans between affiliated companies must be approved in advance by the Securities and Exchange Commission (SEC).
At December 31, 2003, the Company's current liabilities exceed current assets because of the scheduled maturity of $80 million of adjustable rate long-term notes payable in 2004.
To meet short-term cash needs and contingencies, the Company has various internal and external sources of liquidity. At the beginning of 2004, the Company had approximately $69 million of cash and cash equivalents and $100 million of unused credit arrangements with banks, as shown in the following table. The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other Southern Company retail operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other operating company. The obligations of each company under these arrangements are several; there is no cross affiliate credit support. At December 31, 2003, the Company had no outstanding commercial paper or extendible commercial notes.
At the beginning of 2004, the bank credit arrangements are as follows:
Expires ---------------------------------- Total Unused 2004 2005 & Beyond ---------------------------------------------------------- (in millions) $100 $100 $100 - ----------------------------------------------------------
See the Statement of Cash Flows and Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
Financing Activities
During 2003, the Company continued a program to retire higher-cost debt and replace these securities with lower-cost capital. See the Statements of Cash Flows for further details. As a result, composite financing rates have decreased as follows:
2003 2002 2001 ------------------------------------------------------------ Composite interest rate on long-term debt 3.26% 4.10% 4.60%
Composite preferred stock dividend rate 6.33% 6.33% 6.33%
Composite distribution rate on preferred securities 7.20% 7.20% 7.75% ------------------------------------------------------------
In February 2003, the Company redeemed $33 million of 7.45% first mortgage bonds, originally due in 2023, and $850,000 of 5.8% pollution control revenue bonds, originally due in 2007.
In April 2003, the Company issued $90 million of Series E 5-5/8% Senior Notes due May 1, 2033. The proceeds from this sale were used to repay at maturity $35 million of the Company's Series B 6.05% Senior Notes due May 1, 2003, to redeem the $51.6 million outstanding principal amount of the Company's Series A 6.75% Senior Insured Quarterly Notes due June 30, 2038, and to repay a portion of the Company's outstanding short-term indebtedness.
Off-Balance Sheet Financing Arrangements
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." Juniper has also entered into leases with other parties unrelated to the Company. The assets leased by the Company comprise less than 50 percent of Juniper's assets. In accordance with FASB Interpretation No. 46, the Company does not consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease under FASB Statement No. 13. Accordingly, the lease is not reflected on the Company's Balance Sheets.
The initial lease term ends in 2011, and the lease includes a purchase and
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renewal option based on the cost of the Facility at the inception of the lease, which was $369 million. The Company is required to amortize approximately four percent 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 percent 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 percent 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 agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain fixed-price physical gas purchase contracts that could require collateral -- but not accelerated payment -- in the event of a credit rating change to below investment grade; however, at December 31, 2003, this exposure was immaterial.
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 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.
The weighted average interest rate on variable long-term debt outstanding at December 31, 2003 was 1.3 percent. Based on the Company's overall variable rate long-term debt exposure at December 31, 2003, a near-term 100 basis point change in interest rates would affect annualized interest expense by approximately $1.6 million. The Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term.
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, 2003, exposure from these activities was not material to the Company's financial statements.
In addition, at the instruction of the MPSC, the Company has implemented a fuel-hedging program. At December 31, 2003, exposure from these activities was not material to the Company's financial statements.
Fair value of changes in energy contracts and year-end valuations are as follows:
Change in Fair Value ----------------------------- 2003 2002 - -------------------------------------------------------------- (in thousands) Contracts beginning of year $ 12,864 $ (3,830) Contracts realized or settled (17,210) (1,562) Current period changes 6,816 18,256 - -------------------------------------------------------------- Contracts end of year $ 2,470 $ 12,864 ==============================================================
At December 31, 2003, all of these contracts are actively quoted and mature within one year. These contracts are related 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 fuel cost recovery clause. Gains and losses on contracts that do not represent hedges are recognized in the Statements of Income as incurred. For the years ended December 31, 2003, 2002, and 2001, these amounts were not material.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2003 Annual Report
At December 31, 2003, the fair value of derivative energy contracts was reflected in the financial statements as follows:
Amounts ------------------------------------------------------------ (in thousands) Regulatory liabilities, net $2,468 Net income 2 ------------------------------------------------------------ Total fair value $2,470
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 further 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 $80 million for 2004, $70 million for 2005, and $98 million for 2006. Environmental expenditures included in these amounts are $2.7 million, $5.3 million, and $12.6 million for 2004, 2005, and 2006, respectively. Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Other funding requirements relate to obligations associated with scheduled maturities of long-term debt and preferred securities, as well as the related interest and distributions, preferred 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) Mississippi Power Company 2003 Annual Report
Cautionary Statement Regarding Forward-Looking Information
The Company's 2003 Annual Report includes forward-looking statements in addition to historical information. Forward-looking information includes, among other things, statements concerning the estimated construction and other expenditures, projections for energy sales, and earnings growth. 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 comparable terminology. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include: o 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 and also changes in environmental, tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
o current and future litigation, regulatory investigations, proceedings or inquiries, including the pending EPA civil action against the Company; o the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates; o the impact of fluctuations in commodity prices, interest rates, and customer demand; o available sources and costs of fuels; o ability to control costs; o investment performance of the Company's employee benefit plans; o advances in technology; o state and federal rate regulations and pending and future rate cases and negotiations; o effects of and changes in political, legal, and economic conditions and developments in the United States, including the current soft economy; o internal restructuring or other restructuring options that may be pursued; o potential business strategies, including acquisitions or dispositions of assets, which can not be assumed to be completed or beneficial to the Company; o the ability of counterparties of the Company to make payments as and when due; o the ability to obtain new short- and long-term contracts with neighboring utilities; o the direct or indirect effects on the Company's business resulting from the terrorist incidents on September 11, 2001, or any similar incidents or responses to such incidents; o financial market conditions and the results of financing efforts, including the Company's credit ratings; o the ability of the Company to obtain additional generating capacity at competitive prices; o weather and other natural phenomena; o the direct or indirect effects on the Company's business resulting from the August 2003 power outage in the Northeast, or any similar incidents; o the effect of accounting pronouncements issued periodically by standard-setting bodies; and o other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed from time to time by the Company with the SEC.
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NOTES TO FINANCIAL STATEMENTS Mississippi Power Company 2003 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 five retail operating companies, Southern Power Company (Southern Power), Southern Company Services (SCS), Southern Communications Services (Southern LINC), Southern Company Gas (Southern Company GAS), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The retail operating companies - Alabama Power Company, Georgia Power Company, Gulf Power Company, the Company, and Savannah Electric and Power Company - provide electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the state of Mississippi and to wholesale customers in the Southeast. Southern Power constructs, owns, and manages Southern Company's competitive generation assets and sells electricity at market-based rates in the wholesale market. Contracts among the retail operating companies and Southern Power - related to jointly owned generating facilities, interconnecting transmission lines, or the exchange of electric power - are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission (SEC). SCS--the system service company -- provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern Company GAS is a competitive retail natural gas marketer serving customers in Georgia. Southern Holdings is an intermediate holding subsidiary for Southern Company's investments in synthetic fuels and leveraged leases and an energy services business. Southern Nuclear operates and provides services to Southern Company's nuclear power plants.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries, including the Company, are subject to the regulatory provisions of PUHCA. In addition, the Company is subject to regulation by the FERC and the Mississippi Public Service Commission (MPSC). 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.
Certain prior years' data presented in the financial statements have been reclassified to conform with the current year presentation.
Affiliate Transactions
The Company has an agreement with SCS under which the following services are rendered to the Company at 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 $46.2 million, $43.6 million, and $44.1 million during 2003, 2002 and 2001, respectively. Cost allocation methodologies used by SCS are approved by the SEC, and management believes they are reasonable.
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 $6.6 million, $6.4 million and, $5.5 million in 2003, 2002, and 2001, respectively. The Company also has an 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 $17.7
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NOTES (continued) Mississippi Power Company 2003 Annual Report
million, $16.6 million, and $13.1 million in 2003, 2002 and, 2001. See Note 4 for additional information.
The retail operating companies (including the Company), Southern Power, and Southern Company GAS may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as an agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements.
Revenues and Fuel Costs
Energy and other revenues are recognized as services are rendered. 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 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 actual allowable amounts and the amounts included in rates.
The Company has a diversified base of customers. For the year ended December 31, 2003, Dynegy, Inc. (Dynegy) accounted for approximately 14.8 percent of revenues as a result of non-recurring contract termination revenues. See Note 3 under "Contract Termination" for additional information. No other single customer or industry accounted for 10 percent or more of revenues in 2003. For the years ended December 31, 2002 and 2001, no single customer or industry accounted for 10 percent or more of revenues. For all periods presented, uncollectible accounts continued to average less than 1/2 percent of revenues.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
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NOTES (continued) Mississippi Power Company 2003 Annual Report
Regulatory assets and (liabilities) reflected in the Balance Sheets at December 31 relate to:
2003 2002 Note - ------------------------------------------------------------------ (in thousands) (in thousands) Deferred income tax charges $ 12,125 $ 12,617 (a) Vacation pay 5,766 5,782 (b) Loss on reacquired debt 10,201 7,776 (c) Fuel hedging asset 2,397 14,558 (d) Asset retirement obligations 689 - (a) Other assets - 49 (e) Property damage reserve (6,796) (5,077) (e) Deferred income tax credits (23,279) (20,798) (a) Other cost of removal obligations (80,588) (69,873) (a) Plant Daniel capacity (60,300) - (f) Fuel-hedging liabilities (3,870) (14,990) (d) Other liabilities (1,756) (2,450) (e) - ------------------------------------------------------------- Total $ (145,411) $ (72,406) =============================================================
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) Recorded as earned by employees and recovered as paid, generally within one year. (c) 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. (d) 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 fuel cost recovery clause. (e) Recorded and recovered or amortized as approved by the MPSC. (f) See Note 3 under "Retail Regulatory Filing."
In the event that a portion of the Company's operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair value. All regulatory assets and liabilities are to be reflected in rates.
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.4 percent in 2003, 3.4 percent in 2002, and 3.5 percent in 2001. 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. Depreciation expense includes an amount for the expected cost of removal of facilities.
Asset Retirement Obligations and Other Costs of Removal
In accordance with regulatory requirements, prior to January 2003, the Company followed the industry practice of accruing for the ultimate cost of retiring most long-lived assets over the life of the related asset as part of the annual depreciation expense provision. In accordance with SEC requirements, such amounts are reflected on the balance sheet as regulatory liabilities. Effective January 1, 2003, the Company adopted FASB Statement No.143, Accounting for Asset Retirement Obligations. Statement No. 143 establishes new accounting and reporting standards for legal obligations associated with the ultimate costs of retiring long-lived assets. The present value of the ultimate costs for an asset's future retirement must be recorded in the period in which the liability is incurred. The costs must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Additionally, Statement No. 143 does not permit the continued accrual of future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. However, the Company has received guidance regarding accounting for the financial statement impacts of Statement No. 143 from the MPSC and will continue to recognize the accumulated removal costs for other obligations as a regulatory liability. Therefore, the Company has no cumulative effect to net income resulting from the adoption of Statement No. 143.
The Company has retirement obligations related to various landfill sites, ash ponds, and underground storage tanks. The Company has also identified retirement obligations related to certain transmission and distribution
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facilities. However, liabilities for the removal of these transmission and distribution assets have not been recorded because no reasonable estimate can be made regarding the timing of the obligations. The Company will continue to recognize in the income statement allowed removal costs in accordance with its regulatory treatment. Any difference between costs recognized under Statement No. 143 and those reflected in rates are recognized as either a regulatory asset or liability and are reflected in the Balance Sheets.
Details of the asset retirement obligations included in the Balance Sheets are as follows:
- ------------------------------------------------------------- (in millions) Balance, beginning of year $ - Liabilities incurred 2.4 Liabilities settled - Accretion 0.1 Cash flow revisions - - ------------------------------------------------------------- Balance, end of year $2.5 =============================================================
If Statement No. 143 had been adopted on January 1, 2002, the pro-forma asset retirement obligations would have been $1 million.
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 cost of funds used during construction, if applicable. 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.
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 either by the amount of regulatory disallowance or by estimating the fair value of the asset and recording a loss for the amount of the carrying value that is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment provision is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
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 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 used or installed.
Stock Options
Southern Company provides non-qualified stock options to a large segment of the Company's employees ranging from line management to executives. The Company accounts for its stock-based compensation plans in accordance with Accounting Principles Board Opinion No. 25. Accordingly, no compensation expense has been recognized because the exercise price of all options granted equaled the fair-market value on the date of grant. When options are exercised, the Company receives a capital contribution from Southern Company equivalent to the related income tax benefit.
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
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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 or regulatory assets or liabilities as appropriate 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.
In June 2001, the MPSC approved the Company's request to implement an Energy Cost Management Clause (ECM). ECM, 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 was approved by the FERC in 2002.
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 amount did not equal the fair value at December 31 were as follows:
Carrying Fair Amount Value - --------------------------------------------------------------- (in millions) Long-term debt: At December 31, 2003 $282 $286 At December 31, 2002 $313 $313 Preferred securities: At December 31, 2003 $35 $37 At December 31, 2002 $35 $36 ==============================================================
The fair values were based on either closing market price or closing price of comparable instruments.
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 regulatory authorities, the Company accrues for the cost of such damage by charging expense and crediting an accumulated provision. The cost of repairing damage resulting from such events that individually exceed $50,000 is charged to the accumulated provision as ordered by the MPSC. The annual accruals may range from $1.5 million to $4.6 million with a maximum reserve totaling $23 million. The Company accrued $2.5 million in 2003, $1.8 million in 2002, and $2.5 million in 2001. As of December 31, 2003, the accumulated provision amounted to $6.8 million.
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 additional minimum pension liability, less income taxes and reclassifications for amounts included in net income.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan that covers substantially all employees. The Company also provides certain non-qualified benefit plans for a selected group of management and highly compensated employees. The plan is funded in accordance with Employee Retirement Income Security Act (ERISA) requirements. No contributions to the plan are expected for the year ending December 31, 2004. The Company provides certain medical care and life insurance benefits for retired employees. Benefits under these non-qualified plans are funded on a cash basis. The Company funds trusts to the extent deductible under federal income tax regulations or the extent required by
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the MPSC and the FERC. For the year ended December 31, 2004, postretirement benefit contributions are expected to total approximately $330,000.
The measurement date for plan assets and obligations is September 30 for each year. In 2002, the Company adopted several pension and postretirement benefit plan changes that had the effect of increasing benefits to both current and future retirees.
Pension Plans
The accumulated benefit obligation for the pension plans was $188 million and $161 million for 2003 and 2002, respectively. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:
Projected Benefit Obligations - ------------------------------------------------------------- 2003 2002 - ------------------------------------------------------------- (in thousands) Balance at beginning of year $186,443 $172,167 Service cost 5,607 5,259 Interest cost 11,964 12,674 Benefits paid (9,317) (8,386) Actuarial loss and employee transfers 12,992 528 Amendments - 4,200 - ------------------------------------------------------------- Balance at end of year $207,689 $186,442 =============================================================
Plan Assets ------------------------ 2003 2002 - ------------------------------------------------------------- (in thousands) Balance at beginning of year $188,839 $211,546 Actual return on plan assets 30,024 (14,089) Benefits paid (8,512) (7,875) Employee transfers (66) (743) - ------------------------------------------------------------- Balance at end of year $210,285 $188,839 =============================================================
The plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Service (IRS) revenue code. The Company's investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.
Plan Assets --------------------- Target 2003 2002 - -------------------------------------------------------------- Domestic equity 37% 37% 35% International equity 20 20 18 Global fixed income 26 24 25 Real estate 10 11 12 Private equity 7 8 10 - -------------------------------------------------------------- Total 100% 100% 100% ==============================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
2003 2002 - ----------------------------------------------------------------- (in thousands) Funded status $ 2,596 $ 2,396 Unrecognized transition obligation (1,635) (2,180) Unrecognized prior service cost 15,004 16,669 Unrecognized net gain (5,507) (9,087) - ---------------------------------------------------------------- Prepaid pension asset, net 10,458 7,798 Portion included in benefit obligations 7,709 7,195 - ---------------------------------------------------------------- Total prepaid assets recognized in the Balance Sheets $18,167 $14,993 ================================================================
In 2003 and 2002, amounts recognized in the Balance Sheets for accumulated other comprehensive income were $2.3 million and $2.0 million, respectively. Intangible assets recognized were $1.4 million in 2003 and $1.7 million in 2002.
Components of the pension plans' net periodic cost were as follows:
2003 2002 2001 - --------------------------------------------------------------- (in thousands) Service cost $ 5,607 $ 5,259 $ 4,797 Interest cost 11,965 12,674 11,818 Expected return on plan assets (18,329) (18,380) (17,328) Recognized net gain (1,847) (2,654) (3,012) Net amortization 862 650 511 - --------------------------------------------------------------- Net pension income $ (1,742) $ (2,451) $ (3,214) ===============================================================
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Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:
Accumulated Benefit Obligations ----------------------- 2003 2002 ----------------------------------------------------------- (in thousands) Balance at beginning of year $61,168 $51,523 Service cost 1,149 959 Interest cost 3,897 3,781 Benefits paid (2,813) (3,320) Actuarial loss and employee transfers 8,785 8,225 ----------------------------------------------------------- Balance at end of year $72,186 $61,168 ===========================================================
Plan Assets ----------------------- 2003 2002 ----------------------------------------------------------- (in thousands) Balance at beginning of year $16,078 $16,269 Actual return on plan assets 1,979 (516) Employer contributions 2,941 3,645 Benefits paid (2,813) (3,320) ----------------------------------------------------------- Balance at end of year $18,185 $16,078 ===========================================================
Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the IRS revenue code. The Company's investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.
Plan Assets ----------------------- Target 2003 2002 - ---------------------------------------------------------------- Domestic equity 27% 27% 24% International equity 14 14 13 Global fixed income 47 45 47 Real estate 7 8 9 Private equity 5 6 7 - ---------------------------------------------------------------- Total 100% 100% 100% ================================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows:
Accrued Costs --------------------- 2003 2002 - ---------------------------------------------------------------- (in thousands) Funded status $(54,001) $(45,090) Unrecognized transition obligation 3,235 3,582 Unrecognized prior service cost 1,610 1,715 Unrecognized net gain 18,503 10,216 Fourth quarter contributions 926 1,029 - ---------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $(29,727) $(28,548) ================================================================
Components of the postretirement plans' net periodic cost were as follows:
Net Periodic Costs - ---------------------------------------------------------------- 2003 2002 2001 - ---------------------------------------------------------------- (in thousands) Service cost $ 1,149 $ 959 $ 922 Interest cost 3,898 3,781 3,411 Expected return on plan assets (1,598) (1,514) (1,409) Transition obligation 346 346 346 Prior service cost 106 106 80 Recognized net loss 116 - (38) - ---------------------------------------------------------------- Net postretirement cost $ 4,017 $ 3,678 $ 3,312 ================================================================
The weighted average rates assumed in the actuarial calculations for both the pension plan and postretirement benefits plans were as follows:
2003 2002 2001 - ---------------------------------------------------------------- Discount 6.00% 6.50% 7.50% Annual salary increase 3.75 4.00 5.00 Long-term return on plan assets 8.50 8.50 8.50 - ----------------------------------------------------------------
The Company determined the long-term rate of return on based 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 accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 8.25 percent for 2003, decreasing gradually to 5.25 percent through the year 2010 and remaining at that level thereafter. An annual increase or decrease in the
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assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2003 as follows:
1 Percent 1 Percent Increase Decrease - ---------------------------------------------------------------- (in thousands) Benefit obligation $5,499 $4,863 Service and interest costs 329 290 - ----------------------------------------------------------------
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee's base salary. Total matching contributions made to the plan for the years 2003, 2002, and 2001 were $2.7 million, $2.6 million, and $2.5 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, and citizen enforcement of environmental requirements, 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 litigation against the Company cannot be predicted at this time; however, 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.
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 Alabama Power, Georgia Power, and SCS. The complaint alleged violations of the New Source Review (NSR) provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia and violations of related state laws. The civil action requested penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued to the retail operating companies notices of violation relating to 10 generating facilities, which include the five facilities mentioned previously and the Company's Plants Watson and Greene County. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notices of violation and to add Gulf Power, the Company, and Savannah Electric as defendants.
In August 2000, the U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and granted SCS' motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. In March 2001, the court granted the EPA's motion to add Savannah Electric as a defendant, but it denied the motion to add Gulf Power and the Company based on lack of jurisdiction in Georgia over those companies. As directed by the court, the EPA refiled its amended complaint limiting claims to those brought against Georgia Power and Savannah Electric. In addition, the EPA refiled its claims against Alabama Power in the U.S. District Court for the Northern District of Alabama. These complaints allege violations with respect to eight coal-fired generating facilities in Alabama and Georgia, and they request the same kinds of relief as was requested in the original complaint, i.e. penalties and injunctive relief, including installation of the best available control technology. The EPA has not refiled against Gulf Power, the Company, or SCS.
The actions against Alabama Power, Georgia Power, and Savannah Electric were stayed in the spring of 2001 during the appeal of a very similar NSR enforcement action against the Tennessee Valley Authority (TVA) before the U.S. Court of Appeals for the Eleventh Circuit. The TVA appeal involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and Savannah Electric. Because the final resolution of the TVA appeal could have a significant impact on Alabama Power and Georgia Power, both companies have been involved in that appeal. On June 24, 2003, the court of appeals issued its
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ruling in the TVA case. It found unconstitutional the statutory scheme set forth in the Clean Air Act that allowed the EPA to impose penalties for failing to comply with an administrative compliance order, like the one issued to TVA, without the EPA having to prove the underlying violation. Thus, the court of appeals held that the compliance order was of no legal consequence, and TVA was free to ignore it. The court did not, however, rule directly on the substantive legal issues about the proper interpretation and application of certain NSR provisions that had been raised in the TVA appeal. On September 16, 2003, the court of appeals denied the EPA's request for a rehearing of the decision. On February 13, 2004, the EPA petitioned the U.S. Supreme Court to review the decision of the court of appeals. The EPA also filed a motion to lift the stay in the action against Alabama Power. At this time, no party to the Georgia Power and Savannah Electric action, which was administratively closed two years ago, has asked the court to reopen that case.
Since the inception of the NSR proceedings against Georgia Power, Alabama Power, and Savannah Electric, the EPA has also been proceeding with similar NSR enforcement actions against other utilities, involving many of the same legal issues. In each case, the EPA alleged that the utilities failed to comply with the NSR permitting requirements when performing maintenance and construction activities at coal-burning plants, which activities the utilities considered to be routine or otherwise not subject to NSR. In 2003, district courts addressing these cases issued opinions that reached conflicting conclusions.
In October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act clarifying the scope of the existing Routine Maintenance, Repair, and Replacement exclusion. On December 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit stayed the effectiveness of these revisions pending resolution of related litigation. In January 2004, the Bush Administration announced that it would continue to enforce the existing rules.
The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. An adverse outcome in any one of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
Right of Way Litigation
Southern Company and certain of its subsidiaries, including the Company, Georgia Power, Gulf Power, and Southern Telecom (collectively, defendants), have been named as defendants in numerous lawsuits brought by landowners since 2001 regarding the installation and use of fiber optic cable over defendants' rights of way located on the landowners' property. 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 by defendants exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment. The plaintiffs seek compensatory and punitive damages and injunctive relief. The Company believes that the Company has complied with the applicable laws and that the plaintiffs' claims are without merit. An adverse outcome in these matters could result in substantial judgments; however, the final outcome of these matters cannot now be determined.
In addition, in late 2001, certain subsidiaries of Southern Company, including Alabama Power, Georgia Power, Gulf Power, the Company, Savannah Electric, and Southern Telecom (collectively, defendants), 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 the telecommunications company in pending and future right of way litigation. The Company believes that the plaintiff's claims are without merit. 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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Contract Termination
On May 21, 2003, the Company entered into an agreement with Dynegy to resolve all outstanding matters related to a capacity sales contract with a subsidiary of Dynegy. Under the terms of the agreement, Dynegy made a cash payment of $75 million to the Company. The contract between the Company and Dynegy was terminated effective October 31, 2003. The termination payment from Dynegy resulted in the Company recognizing a gain of $38 million after tax.
Retail Regulatory Filing
The Company's retail base rates are set under Performance Evaluation Plan (PEP), a rate plan originally approved in 1986 and modified from time to time since its inception. See "2001 Retail Rate Case" for further information on the 2002 modification. 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: the Company's ability to maintain low rates for customers, and the Company's performance as measured by two additional indicators that emphasize customer satisfaction and providing reliable service to the customer. PEP provides for semiannual evaluations of the Company's performance-based return on investment. Any change in rates is limited to two percent of retail revenues per evaluation period. PEP will remain in effect until the MPSC modifies, suspends, or terminates the plan.
On December 5, 2003, the Company filed a request with the MPSC to include 266 megawatts of Plant Daniel Units 3 and 4 generating capacity not currently included in jurisdictional cost of service. See "2001 Retail Rate Case" for further information on the current cost allocation for this capacity. In addition, the Company proposed to modify certain provisions of PEP. The proposed changes include (1) the use of a forward-looking, rather than a historical, test year, (2) adjustments to the performance indicator mechanism, and (3) an annual, rather than semi-annual, evaluation period.
As part of the Company's proposal to include the additional Plant Daniel capacity in retail rates, the MPSC issued an interim accounting order in December 2003 directing the Company to expense and record in 2003 a regulatory liability in the amount of approximately $60 million while the MPSC fully considers the entire request. However, if the MPSC ultimately denies the Company's request, the regulatory liability will be required to be reversed.
The Company expects the MPSC to render a final order in the second quarter of 2004 on the inclusion of the additional Plant Daniel capacity in rates, the amortization period for the regulatory liability, and the requested changes to PEP.
Environmental Compliance Overview Plan
The MPSC approved the Company's Environmental Compliance Overview Plan (ECO Plan) in 1992. The ECO Plan establishes procedures to facilitate the MPSC's overview of the Company's environmental strategy and provides for recovery of costs (including costs of capital) associated with environmental projects approved by the MPSC. Under the ECO Plan, any increase in the annual revenue requirement is limited to two percent of retail revenues. However, the ECO Plan also provides for carryover of any amount over the two percent 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. The Company recovers such costs under the ECO Plan as they are incurred, as provided for in the Company's 1995 ECO Plan Order. The Company filed its 2004 ECO Plan in January 2004, which, if approved as filed, will result in a slight decrease in customer prices.
2001 Retail Rate Case
In December 2001, the MPSC approved an annual retail rate increase of approximately $39 million, which took effect in January 2002. In October 2000, the MPSC approved a cost allocation that allocated a pro-rata share of the Plant Daniel Units 3 and 4 leased capacity, along with the Company's existing generation, to the retail jurisdiction. The MPSC's December 2001 order approved these cost allocations.
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Additionally, the MPSC ordered the Company to reactivate semi-annual evaluations under PEP, beginning with the 12-month period ending December 31, 2002. In May 2002, the MPSC issued an order adopting new return on equity models to be used in the PEP process that are very similar to those that established the $39 million rate increase.
Potentially Responsible Party Status
In 2003, the Texas Commission on Environmental Quality (TCEQ) designated the Company as a potentially responsible party in connection with the cleanup of a site in Texas owned by a company that performed rebuilds and scrapping on electric transformers for the Company and many other utilities. 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 perform off-site removal of polychlorinated biphenyl (PCB) contaminated soil. Amounts expensed during 2003 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.
FERC Matters
Market-Based Rate Authority
The Company has obtained FERC approval to sell power to nonaffiliates at market-based prices under specific contracts. Through SCS, as agent , the Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities' applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company's retail operating companies, and found them and others to be "pivotal suppliers" in their service areas and ordered the implementation of several mitigation measures. SCS, on behalf of the Company and the other retail operating companies sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. SCS, on behalf of the Company and the other retail operating companies, submitted comments to the FERC in 2002 regarding these issues. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. The Company anticipates that the FERC will address the requests for rehearing in the near future. The final outcome of this matter will depend on the form in which the SMA test and mitigation measures rules may be ultimately adopted and cannot be determined at this time.
Wholesale Customer Settlement Agreement
In February 2002, the Company reached an agreement with certain of its wholesale customers to increase its wholesale tariff rates effective June 1, 2002. The FERC accepted the settlement agreement and placed the new tariff rates in effect without modification. The settlement agreement results in an annual increase of approximately $10.5 million, the adoption of ECM and the cost allocation of Plant Daniel Units 3 and 4, similar to the plans approved by the Company's retail jurisdiction.
Transmission Facilities Agreement
In January 2002, the FERC began conducting an investigation to determine whether the cost of debt and the cost of preferred stock reflected in the amount charged under the Transmission Facilities Agreement between Entergy Corp. and the Company, when considered in light of other aspects of the contract, yields an overall just and reasonable rate. In July 2003, the FERC approved a settlement between the Company and the FERC staff. The impact of the settlement provides for no refund of prior revenues collected and a minimal change in revenues effective in 2004.
4. JOINT OWNERSHIP AGREEMENTS
The Company and Alabama Power own as tenants in common Units 1 and 2 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 at Plant Daniel, which is located in Mississippi and operated by the Company.
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At December 31, 2003, the Company's percentage ownership and investment in these jointly owned facilities were as follows:
Company's Generating Total Percent Gross Accumulated Plant Capacity Ownership Investment Depreciation ------------------------------------------------------------- (Megawatts) (in thousands) Greene County Units 1 and 2 500 40% $ 68,504 $ 36,733
Daniel Units 1 and 2 1,000 50% $240,032 $116,815 -------------------------------------------------------------
The Company's proportionate share of plant operating expenses is included in the Statements of Income.
5. INCOME TAXES
Southern Company and its subsidiaries file a consolidated federal income tax return. Under a joint consolidated income tax 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.
At December 31, 2003, the tax-related regulatory assets and liabilities were $12 million and $23 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.
Details of the federal and state income tax provisions are shown below:
2003 2002 2001 ----------------------------------------------------------------- (in thousands) Total provision for income taxes: Federal -- Current $46,116 $42,603 $43,596 Deferred (6,166) (3,122) (8,661) 39,950 39,481 34,935 ----------------------------------------------------------------- State -- Current 7,761 6,680 6,698 Deferred (2,396) (282) (1,057) ----------------------------------------------------------------- 5,365 6,398 5,641 ----------------------------------------------------------------- Total $45,315 $45,879 $40,576 =================================================================
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:
2003 2002 ---------------------------------------------------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $168,373 $157,087 Basis differences 7,487 7,791 Other 46,689 38,005 ---------------------------------------------------------------- Total 222,549 202,883 ---------------------------------------------------------------- Deferred tax assets: Other property basis differences 15,067 14,501 Pension and other benefits 10,722 9,546 Property insurance 2,599 1,942 Unbilled fuel 5,593 6,048 Other 68,257 42,891 ---------------------------------------------------------------- Total 102,238 74,928 ---------------------------------------------------------------- Total deferred tax liabilities, net 120,311 127,955 Portion included in prepaid expenses (accrued income taxes), net 21,777 18,675 ---------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $142,088 $146,630 =================================================================
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 $1.2 million in each of 2003, 2002, and 2001. At December 31, 2003,
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all investment tax credits available to reduce federal income taxes payable had been utilized.
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:
2003 2002 2001 ------------------------------------------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 2.9 3.4 3.4 Non-deductible book Depreciation .4 0.5 0.5 Other (0.8) (1.0) (0.8) --------------------------------------------------- --------- Effective income tax rate 37.5% 37.9% 38.1% =============================================================
6. CAPITALIZATION
Mandatorily Redeemable Preferred Securities
The Company has formed a certain 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 totaling $36 million, which constitute substantially all assets of the trust. The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the trust's payment obligations with respect to these securities. At December 31, 2003, preferred securities of $35 million were outstanding and recognized as liabilities in the Balance Sheets.
Pollution Control 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, 2003 was $82.7 million.
Long-Term Debt Due Within One Year
A summary of the improvement fund requirements and scheduled maturities and redemptions of long-term debt due within one year at December 31 is as follows:
2003 2002 --------------------------------------------------------------- (in thousands) Bond improvement fund requirement $ 300 $ 634 Less: Portion to be satisfied by certifying property additions 300 634 --------------------------------------------------------------- Cash sinking fund requirement - - Current portion of other long-term debt 80,000 68,350 Pollution control bond cash sinking fund requirements - 850 --------------------------------------------------------------- Total $80,000 $69,200 ==============================================================-
The first mortgage bond improvement fund requirement is one percent of each outstanding series authenticated under the indenture of the Company prior to January 1 of each year, other than first mortgage bonds issued as collateral security for certain pollution control obligations. The requirement must be satisfied by June 1 of each year by depositing cash or reacquiring bonds, or by pledging additional property equal to 1 and 2/3 times such requirement.
In February 2003, the Company redeemed $33 million of 7.45% first mortgage bonds, originally due in 2023, and $850,000 of 5.8% pollution control revenue bonds, originally due in 2007.
Assets Subject to Lien
The Company's mortgage indenture dated as of September 1, 1941, as amended and supplemented, which secures the first mortgage bonds issued by the Company, constitutes a direct first lien on substantially all of the Company's fixed property and franchises.
Bank Credit Arrangements
At the beginning of 2004, the Company had total committed credit agreements with banks for approximately $100 million, all of which was unused. These credit agreements expire in 2004. Some of these agreements allow short-term borrowings to be converted into term loans, payable in eight equal quarterly installments, with the first installment due at the end of the first calendar quarter after the applicable termination date or at an earlier date at the Company's option.
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NOTES (continued) Mississippi Power Company 2003 Annual Report
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 less than 1/8 of 1 percent for the Company. Compensating balances are not legally restricted from withdrawal.
This $100 million in unused credit arrangements provides required liquidity support to the Company's borrowings through a commercial paper program. The Company has $60 million available to support its commercial paper program. At December 31, 2003, the Company had no outstanding commercial paper or extendible commercial notes. During 2003, the peak amount outstanding for commercial paper was $33 million and the average amount outstanding was $4.2 million. The average annual interest rate on commercial paper was 1.3 percent in 2003. The credit arrangements also provide support to the Company's variable daily rate pollution control bonds.
Financial Instruments
The Company enters into energy-related derivatives to hedge exposures to electricity, natural 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 MPSC. The Company enters into hedges of forward electricity sales.
At December 31, 2003, the fair value of derivative energy contracts was reflected in the financial statements as follows:
Amounts ------------------------------------------------------------ (in thousands) Regulatory liabilities, net $ 2,468 Net income 2 ------------------------------------------------------------ Total fair value $ 2,470 ============================================================
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.
Dividend Restrictions
The Company's first mortgage bond indenture and the corporate charter contain various common stock dividend restrictions. At December 31, 2003, approximately $118 million of retained earnings was restricted against the payment of cash dividends on common stock under the most restrictive terms of the mortgage indenture or corporate charter.
In accordance with the PUHCA, the Company is also restricted from paying common dividends from paid-in capital without SEC approval.
7. COMMITMENTS
Construction Program
The Company is engaged in continuous construction programs, currently estimated to total $80 million in 2004, $70 million in 2005, and $98 million in 2006. 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; revised load growth estimates; changes in environmental regulations; changes in FERC rules and transmission regulations; increasing costs of labor, equipment and materials; and cost of capital. At December 31, 2003, 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 lease combined cycle units at Plant Daniel. 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 the contract.
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NOTES (continued) Mississippi Power Company 2003 Annual Report
In general, the LTSA is in effect through two major inspection cycles of the units. Scheduled payments to GE 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 $6 and $11 million for 2003 and 2002, respectively, which is included in maintenance expense on the Statements of Income. Remaining payments to GE under this agreement are currently estimated to total $174 million over the next 17 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.
In general, this LTSA is in effect through two major inspection cycles. Scheduled payments to ABB are made at various intervals based on actual operating hours of the unit. Payments to ABB under this agreement are currently estimated to total $6.8 million over the remaining life of the agreement, which is approximately 4 years. However, the LTSA contains various cancellation provisions at the option of the Company. Payments made to ABB 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.
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 fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Natural gas purchase commitments contain given volumes with prices based on various indices at the time of delivery. Amounts included in the chart below represent estimates based on New York Mercantile future prices at December 31, 2003. Total estimated minimum long-term obligations at December 31, 2003 were as follows:
Natural Year Gas Coal -------------------------------------------------- (in millions) 2004 $140 $174 2005 83 86 2006 67 65 2007 45 21 2008 6 - 2009 and there after 54 - - --------------------------------------------------- Total commitments $395 $346 ===================================================
Additional commitments for fuel will be required to supply the Company's future needs.
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company retail operating companies, Southern Power, and Southern Company GAS. Under these agreements, each of the retail operating companies, Southern Power, and Southern Company GAS may be jointly and severally liable. The creditworthiness of Southern Power and Southern Company GAS is currently inferior to the creditworthiness of the retail operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other operating companies to insure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power or Southern Company GAS as a contracting party under these agreements.
Operating Leases
Railcar Leases
In 1989, the Company and Gulf Power jointly entered into a twenty-two year operating lease agreement for the use of 495 aluminum railcars. In 1994, a second lease agreement for the use of 250 additional aluminum railcars was also entered into for twenty-two years. The Company has the option to purchase the 745 railcars at the greater of lease termination value or fair market value, or to renew the leases at the end of the lease term. Both of these leases are for the transport of coal to Plant Daniel.
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NOTES (continued) Mississippi Power Company 2003 Annual Report
Gulf Power, as joint owner of Plant Daniel Units 1 and 2, is responsible for one half of the lease costs. The Company's share (50%) of the leases, charged to fuel stock and recovered through the fuel cost recovery clause, was $1.9 million in 2003, $1.9 million in 2002, and $1.9 million in 2001. The Company's annual lease payments for 2004 through 2008 will average approximately $2 million and after 2008, lease payments total in aggregate approximately $8 million.
Plant Daniel Combined Cycle Generating Units
In May 2001, the Company began the initial 10-year term of the lease agreement signed in 1999 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 MPSC. 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 Filing" for a description of the Company's PEP formula 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 percent of Juniper's assets. In accordance with FASB Interpretation No. 46, the Company is not required to consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease under FASB Statement No. 13. 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 $369 million. The Company is required to amortize approximately four percent 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 percent 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 percent 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. The Company has recognized in the Balance Sheets a liability of approximately $15 million for the fair market value of this residual value guarantee. In 2003, approximately $11 million in lease termination costs and $26 million in lease expense were included in other operation expense. The amount of future minimum operating lease payments will be approximately $29 million annually during the initial term.
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, 2003, are as follows:
Year Lease Payments - ------------------------------------------------------------- (in millions) 2004 $29 2005 29 2006 29 2007 29 2008 28 2009 and thereafter 85 - ------------------------------------------------------------- Total commitments $229 =============================================================
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NOTES (continued) Mississippi Power Company 2003 Annual Report
8. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 2003 and 2002 are as follows:
Net Income After Dividends Operating Operating On Preferred Quarter Ended Revenues Income Stock - ------------------------------------------------------------------ (in thousands) March 2003 $193,886 $39,750 $21,396 June 2003 264,360 90,386 53,059 September 2003 227,814 58,317 34,387 December 2003 183,864 (50,786) (35,343)
March 2002 $183,058 $28,873 $13,982 June 2002 205,378 38,457 20,788 September 2002 243,077 60,010 33,384 December 2002 192,652 17,930 4,859 - ------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and the timing of rate changes.
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SAVANNAH ELECTRIC AND POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Savannah Electric and Power Company 2003 Annual Report
The management of Savannah Electric and Power Company has prepared--and is responsible for--the financial statements and related information included in this report. These statements were prepared in accordance with accounting principles generally accepted in the United States and necessarily include amounts that are based on the best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that the accounting records reflect only authorized transactions of the Company. Limitations exist in any system of internal controls, however, based on a recognition that the cost of the system should not exceed its benefits. The Company believes its system of internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's internal accounting controls are evaluated on an ongoing basis by the Company's internal audit staff. The Company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements.
Southern Company's audit committee of its board of directors, composed of four independent directors, provides a broad overview of management's financial reporting and control functions. Additionally, the Controls and Compliance Committee of Savannah Electric and Power Company's board of directors, composed of five outside directors, meets periodically with management, the internal auditors, and the independent public accountants to discuss auditing, internal controls, and compliance matters. The internal auditors and the independent public accountants have access to the members of these committees at any time.
Management believes that its policies and procedures provide reasonable assurance that the Company's operations are conducted according to a high standard of business ethics.
In management's opinion, the financial statements present fairly, in all material respects, the financial position, results of operations, and cash flows of Savannah Electric and Power Company in conformity with accounting principles generally accepted in the United States.
/s/Anthony R. James Anthony R. James President and Chief Executive Officer
/s/K. R. Willis K. R. Willis Vice President, Treasurer, Chief Financial Officer, and Assistant Secretary
March 1, 2004
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INDEPENDENT AUDITORS' REPORT
Savannah Electric and Power Company:
We have audited the accompanying balance sheets and statements of capitalization of Savannah Electric and Power Company (a wholly owned subsidiary of Southern Company) as of December 31, 2003 and 2002, and the related statements of income, comprehensive income, common stockholder's equity, and cash flows for the years then ended. These financial statements are the responsibility of Savannah Electric and Power Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The financial statements of Savannah Electric and Power Company for the year ended December 31, 2001 were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements and included an explanatory paragraph that described a change in the method of accounting for derivative instruments and hedging activities in their report dated February 13, 2002.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, the financial statements (pages II-261 to II-281) present fairly, in all material respects, the financial position of Savannah Electric and Power Company at December 31, 2003 and 2002, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the financial statements, in 2003 Savannah Electric and Power Company changed its method of accounting for asset retirement obligations.
/s/Deloitte & Touche LLP Atlanta, Georgia March 1, 2004
THE FOLLOWING REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH THE COMPANY'S 2001 ANNUAL REPORT ON FORM 10-K AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP. SEE EXHIBIT 23(f)2 FOR ADDITIONAL INFORMATION.
To Savannah Electric and Power Company:
We have audited the accompanying balance sheets and statements of capitalization of Savannah Electric and Power Company (a Georgia corporation and a wholly owned subsidiary of Southern Company) as of December 31, 2001 and 2000, and the related statements of income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2001. 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 auditing standards generally accepted in the 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, the financial statements (pages II-192 through II-206) referred to above present fairly, in all material respects, the financial position of Savannah Electric and Power Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
As explained in Note 1 to the financial statements, effective January 1, 2001, Savannah Electric and Power Company changed its method of accounting for derivative instruments and hedging activities.
/s/Arthur Andersen LLP Atlanta, Georgia February 13, 2002
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Savannah Electric and Power Company 2003 Annual Report
OVERVIEW OF EARNINGS AND BUSINESS - --------------------------------- ACTIVITIES - ----------
Earnings
Savannah Electric and Power Company's net income for 2003 totaled $22.8 million, remaining stable from the prior year. Higher operating expenses and income taxes were generally offset by higher operating revenues, lower depreciation and amortization expenses, and lower interest expenses.
Earnings were $22.9 million in 2002, representing an increase of $0.8 million or 3.7 percent from the prior year. Earnings were up in 2002 primarily due to higher retail revenues, somewhat offset by higher operating expenses. In 2001, earnings were $22.1 million, representing a decrease of $0.9 million or 3.9 percent from the prior year. Earnings in 2001 were down primarily due to lower retail revenues.
Business Activities
The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area of southeastern Georgia.
Several factors affect the opportunities, challenges, and risk of selling electricity. These factors include the Company's ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stricter environmental standards. 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, 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.
RESULTS OF OPERATIONS - ---------------------
A condensed income statement is as follows:
Increase (Decrease) Amount From Prior Year - ---------------------------------------------------------------- 2003 2003 2002 2001 - ---------------------------------------------------------------- (in thousands) Operating revenues $314,055 $14,503 $15,700 $(11,866) - ---------------------------------------------------------------- Fuel 55,308 353 4,159 (6,381) Purchased power 89,505 13,901 2,518 (2,254) Other operation and maintenance 83,621 2,603 10,525 (1,927) Depreciation and amortization 20,499 (2,205) (3,247) 711 Taxes other than income taxes 14,665 208 473 868 - ------------------------------------------------------ --------- Total operating Expenses 263,598 14,860 14,428 (8,983) - ---------------------------------------------------------------- Operating income 50,457 (357) 1,272 (2,883) Other income (expense), net (12,542) 2,959 247 134 Less -- Income taxes 15,108 2,675 702 (1,843) - ---------------------------------------------------------------- Net Income $ 22,807 $ (73) $ 817 $ (906) ================================================================
Revenues
Total operating revenues for 2003 were $314.1 million, reflecting a 4.8 percent increase when compared to 2002. The following table summarizes the factors affecting operating revenues for the past three years:
Amount - ------------------------------------------------------------------- 2003 2002 2001 - ------------------------------------------------------------------- (in thousands) Retail - prior year $285,771 $269,172 $282,622 Change in -- Base rates 2,799 5,101 - Sales growth (1,524) 8,729 (1,541) Weather (263) 2,397 (427) Fuel cost recovery and other 10,962 372 (11,482) - ------------------------------------------------------------------- Retail - current year 297,745 285,771 269,172 - ------------------------------------------------------------------- Sales for resale -- Non-affiliates 5,653 6,354 8,884 Affiliates 6,499 4,075 3,205 - ------------------------------------------------------------------- Total sales for resale 12,152 10,429 12,089 - ------------------------------------------------------------------- Other operating revenues 4,158 3,352 2,591 - ------------------------------------------------------------------- Total operating revenues $314,055 $299,552 $283,852 =================================================================== Percent change 4.8% 5.5% (4.0)% - -------------------------------------------------------------------
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2003 Annual Report
Retail revenues increased 4.2 percent or $12.0 million in 2003, increased $16.6 million in 2002, and declined $13.5 million in 2001. The significant factors driving these changes are shown in the table above. Retail base rates increased reflecting the Georgia Public Service Commission (GPSC) decision effective June 2002. See Note 3 to the financial statements under "Retail Regulatory Matters" for additional information on the Company's 2002 rate order.
Electric rates include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Under the fuel recovery provisions, fuel revenues generally equal fuel expenses--including the fuel component of purchased energy--and do not affect net income. In May 2001, the Company implemented a Fuel Cost Recovery (FCR) rate increase under a GPSC rate order. At the time, the GPSC-approved FCR anticipated a three year recovery of the under-recovered fuel balance. However, due to decreasing fuel costs in late 2001 and early 2002, the Company fully recovered the balance by March 2002 and, in May 2002, the GPSC approved a FCR decrease which more than offset the Company's base rate increase. See Note 3 to the financial statements under "Retail Regulatory Matters" for additional information on the Company's 2002 rate order.
Revenues from sales to non-affiliated utilities are primarily energy related. These sales do not have a significant impact on net income since the energy is generally sold at variable cost.
Sales to affiliated companies vary from year to year depending on demand and the availability and cost of generating resources at each company. These energy sales do not have a significant impact on earnings since the energy is generally sold at variable cost.
Energy Sales
Changes in revenues are influenced heavily by the amount of energy sold each year. Kilowatt-hour (KWH) sales for 2003 and the percent change by year were as follows:
KWH Percent Change ----------- -------------------------- 2003 2003 2002 2001 ----------- ------------------------- (in millions) Residential 1,738 (3.1)% 8.1% (0.7)% Commercial 1,451 (1.8) 6.4 1.4 Industrial 860 8.5 0.7 (1.6) Other 138 (2.6) 4.4 (1.4) ----------- Total retail 4,187 (0.4) 5.9 (0.2) Sales for resale -- Non-affiliates 162 7.7 35.7 43.4 Affiliates 185 47.1 43.4 (1.0) ----------- Total 4,534 1.2% 7.5% 0.6% ===============================================================
In 2003, residential and commercial energy sales decreased from the prior year primarily due to weather-related demand. Industrial sales were higher because of an increase in usage by several industrial customers, reflecting the beginning of an economic recovery from the previous two year slowdown. All three categories benefited from a continued increase in the number of customers served.
In 2002, residential and commercial energy sales increased from the prior year reflecting the positive impact of weather and continued growth in customers. Industrial sales increased slightly, reflecting customer growth, and were offset by a general economic slowdown. In 2001, total retail energy sales were down slightly from the prior year, reflecting a decrease in energy sales of 1.6 percent to industrial customers due to a slowing of the economy. Residential energy sales also decreased reflecting weather-related demand, somewhat offset by customer growth.
Energy sales to retail customers are projected to increase at a compound average growth rate of 2.1 percent during the period 2004 through 2014.
Expenses
Fuel and purchased power costs constitute the single largest expense for the Company. The mix of energy supply is determined primarily by demand, the unit cost of fuel consumed, and the availability and cost of generating units.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2003 Annual Report
The amount and sources of generation, the average cost of fuel per net KWH generated, and the amount and average cost of purchased power were as follows:
2003 2002 2001 -------------------------- Total generation (millions of KWHs) 2,325 2,249 2,350 Sources of generation (percent) -- Coal 94 91 93 Oil 2 1 1 Gas 4 8 6 Average cost of fuel per net KWH generated (cents) 2.38 2.44 2.16 Total purchased power (millions of KWHs) 2,581 2,379 1,960 Average cost of purchased power per net KWH (cents) 3.47 3.18 3.73 - -----------------------------------------------------------------
Fuel expense increased 0.6 percent due to a slight increase in generation offset somewhat by a lower cost of coal in 2003. In 2002, fuel expense increased 8.2 percent due to increased gas usage and a higher cost of coal. In 2001, fuel expense decreased 11.2 percent due to a decrease in generation and a slightly lower average cost of fuel.
Purchased power expense increased $13.9 million or 18.4 percent in 2003 due to increased energy demands and a purchased power agreement between the Company and Southern Power for energy and capacity from Plant Wansley Units 6 and 7 which began in June 2002. Purchased power from non-affiliates decreased 72.5 percent and from affiliates increased 38.6 percent in 2002 due principally to the Plant Wansley purchased power agreement discussed above. Purchased power expense decreased 3.0 percent in 2001 from the prior year primarily due to lower fuel prices. Purchased power from affiliates also included energy purchases which will vary depending on demand and cost of generation resources at each company. These energy costs are recovered through the fuel cost recovery clause and have no significant impact on earnings.
In 2003, other operation and maintenance expenses increased 3.2 percent. Administrative and general expenses increased by $1.0 million primarily due to increases in accounting and auditing services, insurance reserves, and employee benefits expense, somewhat offset by the annual true-up in billings to Georgia Power for charges associated with the jointly owned combustion turbines at the Company's Plant McIntosh. Maintenance expense increased $1.5 million primarily due to a scheduled turbine maintenance outage at Plant Kraft and higher transmission and distribution maintenance expenses.
In 2002, other operation and maintenance expenses increased 14.9 percent. Other operation expense was higher reflecting increased distribution expenses of $0.6 million, increased administrative and general costs of $3.7 million, and $0.5 million associated with new marketing programs. Distribution costs increased to support improved customer reliability. Administrative and general costs were higher primarily due to increases in security, legal, accounting and auditing services, regulatory activities, and employee benefits expenses. Administrative and general expenses were also higher reflecting the annual true-up in billings to Georgia Power for charges associated with the jointly owned combustion turbines at the Company's Plant McIntosh. Maintenance expense in 2002 increased over 2001 primarily as a result of scheduled maintenance outages at Plant Kraft and amortization of expenses for a major maintenance project on the combustion turbines at Plant McIntosh. See Note 3 to the financial statements under "Retail Regulatory Matters" for additional information.
In 2001, other operation expense decreased 4.7 percent reflecting the discontinuation of a marketing program and a decrease in administrative and general expenses. Administrative and general expenses decreased primarily due to the annual true-up in billings to Georgia Power for charges associated with the jointly owned combustion turbines at the Company's Plant McIntosh and lower insurance expenses.
Depreciation and amortization decreased 9.7 percent in 2003 and 12.5 percent in 2002 primarily as a result of discontinuing accelerated depreciation and beginning amortization of the related regulatory liability in June 2002, in accordance with the 2002 GPSC rate order. Depreciation and amortization increased over the prior year by 2.8 percent in 2001 primarily due to additional depreciation charges under a 1998 GPSC accounting order. See Note 3 to the financial statements under "Retail Regulatory Matters" for additional information.
Interest expense decreased in 2003 primarily as a result of a lower principal amount of debt outstanding during the year. Lower interest rates in 2003, 2002, and 2001 also contributed to lower expenses in those years.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2003 Annual Report
Effects of Inflation
The Company is subject to rate regulation that is based on the recovery of historical costs. In addition, the income tax laws are also based on historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that 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 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 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 results of operations for the past three years are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors. These factors affect the opportunities, challenges, and risk of electricity. These factors include the Company's ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stricter environmental standards. 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, 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.
Industry Restructuring
The Company operates as a vertically integrated utility providing electricity to retail customers within the traditional service area of southeastern Georgia. Prices for electricity provided by the Company to retail customers are set by the GPSC under cost-based regulatory principles. Prices for electricity relating to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power are set by the Federal Energy Regulatory Commission (FERC). Retail rates and earnings are reviewed and adjusted periodically within certain limitations based on earned return on equity. See Note 3 to the financial statements for additional information about these and other regulatory matters.
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 Policy Act of 1992 (Energy Act). The Energy Act allowed independent power producers to access a utility's transmission network and sell electricity to other utilities.
Although the Energy Act does not provide for retail customer access, it was a major catalyst for restructuring and consolidations that took place within the utility industry. Numerous federal and state initiatives that promote wholesale and retail competition are in varying stages. Among other things, these initiatives allow retail customers in some states to choose their electricity provider. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While various restructuring and competition initiatives have been discussed in Georgia, none have been enacted. Enactment could require numerous issues to be resolved, including significant ones relating to recovery of any stranded investments, full cost recovery of energy produced, and other issues related to the energy crisis that occurred in California, as well as the August 2003 power outage in the Northeast. The Company does compete with other electric suppliers within the state. In Georgia, most new retail customers with at least 900 kilowatts of connected load may choose their electricity supplier.
Since 2001, merchant energy companies and traditional electric utilities with significant energy marketing and trading activities have come under severe financial pressures. Many of these companies have completely exited or drastically reduced all energy marketing and trading activities and sold foreign and domestic electric infrastructure assets. The Company has not experienced any material adverse financial impact regarding its limited energy trading operations through Southern Company Services (SCS).
Continuing to be a low-cost producer could provide opportunities to increase the size and profitability of the electricity sales business in markets
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2003 Annual Report
that evolve with changing regulation and competition. Conversely, future regulatory changes could adversely affect the Company's growth, and if the Company does not remain a low-cost producer and provide quality service, then energy sales growth could be limited, and this could significantly erode earnings.
Environmental Matters
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action against Alabama Power, Georgia Power, and SCS. The EPA later amended its complaints to add the Company as a defendant alleging violations of the New Source Review (NSR) provisions of the Clean Air Act with respect to eight coal-fired generating facilities in Alabama and Georgia, including the Company's Plant Kraft. 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 actions against Alabama Power, Georgia Power, and the Company have been stayed since the spring of 2001 during the appeal of a very similar NSR action against the Tennessee Valley Authority before the U.S. Court of Appeals for the Eleventh Circuit. The Eleventh Circuit appeal was decided on September 16, 2003 and, on February 13, 2004, the EPA petitioned the U.S. Supreme Court to review the Eleventh Circuit's decision. The EPA also filed a motion to lift the stay in the action against Alabama Power. At this time, no party to the Georgia Power and Savannah Electric action, which was administratively closed two years ago, has asked the court to reopen that case. See Note 3 to the financial statements under "New Source Review Actions" for additional information.
In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. The December 2002 revisions included changes to the regulatory exclusions and the methods of calculating emissions increases. The October 2003 regulations clarified the scope of the existing Routine Maintenance, Repair, and Replacement exclusion. A coalition of states and environmental organizations filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. On December 24, 2003, the court of appeals granted a stay of the October 2003 revisions pending its review of the rules and ordered that its review be conducted on an expedited basis. In January 2004, the Bush Administration announced that it would continue to enforce the existing rules until the courts resolve legal challenges to the EPA's revised NSR regulations. In any event, the final regulations must be adopted by the State of Georgia in order to apply to the Company's facilities. The effect of these final regulations and the related legal challenges cannot be determined at this time.
The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome in this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
Environmental Statutes and Regulations
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. Compliance with these environmental requirements will involve significant costs - -- both capital and operating -- a major portion of which is expected to be recovered through existing ratemaking provisions. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under "Capital Requirements and Contractual Obligations." There is no assurance, however, that all such costs will, in fact, be recovered.
Compliance with the federal Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. The Title IV acid rain provisions of the Clean Air Act, for example, required significant reductions in sulfur dioxide and nitrogen oxide emissions. Title IV compliance was effective in 2000 and associated construction expenditures totaled approximately $2 million.
To help ozone nonattainment areas attain the one-hour ozone standard, in 1998 the EPA issued regional nitrogen oxide reduction rules. Those rules
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required 21 states, including Georgia, to reduce and cap nitrogen oxide emissions from power plants and other large industrial sources. As a result of litigation challenging the rule, the courts required the EPA to complete a separate rulemaking before the requirements can be applied in Georgia. The final EPA rules have not been issued in Georgia. The impact of this rule on the Company will depend on the form in which it is finalized and cannot be determined at this time.
In July 1997, the EPA revised the national ambient air quality standards for ozone and particulate matter. These revisions made the standards significantly more stringent. In the subsequent litigation of these standards, the U.S. Supreme Court found the EPA's implementation program for the new eight-hour ozone standard unlawful and remanded it to the EPA for further rulemaking. During 2003, the EPA proposed implementation rules designed to address the court's concerns. The EPA plans to designate areas as attainment or nonattainment with the new eight-hour ozone standard in April 2004 and with the new fine particulate matter standard by the end of 2004. These designations will be based on air quality data for 2001 through 2003. Although not expected, part or all of the Company's service area may be designated nonattainment under these standards. State implementation plans (SIPs), including new emission control regulations necessary to bring those areas into attainment, could be required as early as 2007. These SIPs could require reductions in sulfur dioxide emissions and could require further reductions in nitrogen oxide emissions from power plants. If so, reductions could be required sometime after 2007. The impact of any new standards will depend on the development and implementation of applicable regulations and cannot be determined at this time.
In January 2004, the EPA issued a proposed Interstate Air Quality Rule to address interstate transport of ozone and fine particles. This proposed rule would require additional year-round sulfur dioxide and nitrogen oxide emission reductions from power plants in the eastern United States in two phases - in 2010 and 2015. The EPA currently plans to finalize this rule by 2005. If finalized, the rule could modify or supplant other SIP requirements for attainment of the fine particulate matter standard and the eight-hour ozone standard. The impact of this rule on the Company will depend upon the specific requirements of the final rule and cannot be determined at this time.
Further reductions in sulfur dioxide and nitrogen oxides could also be required under the EPA's Regional Haze rules. The Regional Haze rules require states to establish Best Available Retrofit Technology (BART) standards for certain sources that contribute to regional haze. The Company has two plants that could be subject to these rules. The EPA's Regional Haze program calls for states to submit SIPs in 2007. The SIPs must contain emission reduction strategies for implementing BART and achieving progress toward the Clean Air Act's visibility improvement goal. In 2002, however, the U.S. Court of Appeals for the District of Columbia Circuit vacated and remanded the BART provisions of the federal Regional Haze rules to the EPA for further rulemaking. The EPA has entered into an agreement that requires proposed revised rules in April 2004 and final rules in 2005. Because new BART rules have not been developed and state visibility assessments for progress are only beginning, it is not possible to determine the effect of these rules on the Company at this time.
The EPA's Compliance Assurance Monitoring (CAM) regulations under Title V of the Clean Air Act require that monitoring be performed to ensure compliance with emissions limitations on an ongoing basis. The regulations require certain facilities with Title V operating permits to develop and submit a CAM plan to the appropriate permitting authority upon applying for renewal of the facility's Title V operating permit. The Company will apply for renewal of certain Title V operating permits in 2004, and some units will likely become subject to CAM requirements, at least for particulate matter. The Company is in the process of developing CAM plans. Because the plans are still under development, the Company cannot determine the costs associated with implementation of the CAM regulations. Actual ongoing monitoring costs are expensed as incurred and are not material for any year presented.
In January 2004, the EPA issued proposed rules regulating mercury emissions from electric utility boilers. The proposal solicits comments on two possible approaches for the new regulations - a Maximum Achievable Control Technology approach and a cap-and-trade approach. Either approach would require significant reductions in mercury emissions from company facilities. The regulations are
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scheduled to be finalized by the end of 2004, and compliance could be required as early as 2007. Because the regulations have not been finalized, the impact on the Company cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent emissions limitations on power plants have been proposed by Congress. Three of these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2003, and the Clean Air Planning Act of 2003, propose to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills also propose to limit emissions of carbon dioxide. The cost impacts of such legislation would depend upon the specific requirements enacted and cannot be determined at this time.
Domestic efforts to limit greenhouse gas emissions have been spurred by international discussions surrounding the Framework Convention on Climate Change and specifically the Kyoto Protocol, which proposes international constraints on the emissions of greenhouse gases. The Bush Administration does not support U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation and has instead announced a new voluntary climate initiative, known as Climate VISION, which seeks an 18 percent reduction by 2012 in the rate of greenhouse gas emissions relative to the dollar value of the U.S. economy. Through Southern Company, the Company is involved in a voluntary electric utility industry sector climate change initiative in partnership with the government. The electric utility sector has pledged to reduce its greenhouse gas intensity 3 percent to 5 percent over the next decade and is in the process of developing a memorandum of understanding with the Department of Energy (DOE) to cover this voluntary program.
The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. The Company has not incurred any significant cleanup costs to date.
Under the Clean Water Act, the EPA has been developing new rules aimed at reducing impingement and entrainment of fish and fish larvae at power plants' cooling water intake structures. On February 16, 2004, the EPA finalized these rules. These rules will require biological studies and, perhaps, retrofits to some intake structures at existing power plants. The impact of these new rules will depend on the results of studies and analyses performed as part of the rules' implementation.
In addition, under the Clean Water Act, the EPA and the Georgia Environmental Protection Division (EPD) are developing total maximum daily loads (TMDLs) for certain impaired waters. Establishment of maximum loads by the EPA or the Georgia EPD may result in lowering permit limits for various pollutants and a requirement to take additional measures to control non-point source pollution (e.g., storm water runoff) at facilities that discharge into waters for which TMDLs are established. Because the effect on the Company will depend on the actual TMDLs and permit limitations established by the implementing agency, it is not possible to determine the effect on the Company at this time.
Several major pieces of environmental legislation are periodically considered for reauthorization or amendment by Congress. These 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 possible additional federal or state legislation or regulations related to global climate change, electromagnetic fields, or other environmental and health concerns could also significantly affect the Company. The impact of any new legislation, changes to existing legislation, or environmental regulations could affect many areas of the Company's operations. The full impact of any such changes cannot, however, be determined at this time.
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FERC Matters
Transmission
In December 1999, the FERC issued its final rule (Order 2000) on Regional Transmission Organizations (RTOs). Order 2000 encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Southern Company and its retail operating companies, including the Company, worked with a number of utilities in the Southeast to develop a for-profit RTO known as SeTrans. In 2002, the sponsors of SeTrans established a Stakeholder Advisory Committee to provide input into the development of the RTO from other sectors of the electric industry, as well as consumers. During the development of SeTrans, state regulatory authorities expressed concern over certain aspects of the FERC's policies regarding RTOs. In December 2003, the SeTrans sponsors announced that they would suspend work on SeTrans because the regulated utility participants, including the Company, had determined that it is highly unlikely to obtain support of both federal and state regulatory authorities. Any impact of the FERC's rule on the Company will depend on the regulatory reaction to the suspension of SeTrans and future developments, which cannot now be determined.
In July 2002, the FERC issued a notice of proposed rulemaking regarding open access transmission service and standard electricity market design. The proposal, if adopted, would among other things: (1) require transmission assets of jurisdictional utilities to be operated by an independent entity; (2) establish a standard market design; (3) establish a single type of transmission service that applies to all customers; (4) assert jurisdiction over the transmission component of bundled retail service; (5) establish a generation reserve margin; (6) establish bid caps for day ahead and spot energy markets; and (7) revise the FERC policy on the pricing of transmission expansions. Comments on the proposal were submitted by many interested parties, including Southern Company, and the FERC has indicated that it has revised certain aspects of the proposal in response to public comments. Proposed energy legislation would prohibit the FERC from issuing the final rule before October 31, 2006, and from making any final rule effective before December 31, 2006. That legislation has been approved by the House of Representatives but remains pending before the Senate. Passage of the legislation now appears in doubt. It is uncertain whether in the absence of legislation the FERC will move forward with any part or all of the proposed rule. Any impact of this proposal on Southern Company and its subsidiaries, including the Company, will depend on the form in which the final rule may be ultimately adopted. The Company's financial statements could be adversely affected by changes in the transmission regulatory structure in its regional power market.
Market-Based Rate Authority
The Company has obtained FERC approval to sell power to nonaffiliates at market-based prices under specific contracts. Through SCS as agent, the Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities' applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company's retail operating companies, and found them to be "pivotal suppliers" in their control area market and ordered the implementation of several mitigation measures. SCS, on behalf of the retail operating companies, sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. SCS, on behalf of the retail operating companies, submitted comments to the FERC in 2002 regarding these issues. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. The Company anticipates that the FERC will address the requests for rehearing in the near future. Regardless of the outcome of the SMA proposal, the FERC retains the ability to modify or withdraw the authorization for any seller to sell at market-based rates, if it determines that the underlying conditions for having such authority are no longer applicable. The final outcome of this matter will depend on the form in which the SMA test and mitigation measures rules may be ultimately adopted and cannot be determined at this time.
Southern Power PPA
The Company plans to retire a 102 megawatt peaking facility in May 2005. In June 2002, the Company entered into a fifteen-year purchased power agreement with Southern Power for 200 megawatts of capacity beginning in June 2005 from the
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planned combined-cycle plant at Plant McIntosh being built and owned by Southern Power. The annual capacity cost is expected to be approximately $15.0 million.
Purchased power agreements (PPAs) by Georgia Power and the Company for Southern Power's Plant McIntosh capacity were certified by the GPSC in December 2002 after a competitive bidding process. In April 2003, Southern Power applied for FERC approval of these PPAs. Interveners opposed the FERC's acceptance of the PPAs, alleging that the PPAs do not meet the applicable standards for market-based rates between affiliates. In July 2003, the FERC accepted the PPAs to become effective as scheduled on June 1, 2005, subject to refund, and ordered that hearings be held. For additional information, see Note 3 to the financial statements under "FERC Matters."
Other Matters
In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash pension costs of approximately $4.3 million, $4.4 million, and $4.0 million pre-tax in 2003, 2002, and 2001, respectively. Future pension costs are dependent on several factors including trust earnings and changes to the plan. Postretirement benefit costs for the Company were approximately $2.7 million in 2003 and $2.6 million in 2002 and 2001 and are expected to continue to trend upward. A portion of pension and postretirement benefit costs is capitalized based on construction-related labor charges. For more information regarding pension and postretirement benefits, see Note 2 to the financial statements.
On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act). The Medicare Act introduces a prescription drug benefit for Medicare-eligible retirees starting in 2006, as well as a federal subsidy to plan sponsors like the Company that provide prescription drug benefits. In accordance with FASB Staff Position No. 106-1, the Company has elected to defer recognizing the effects of the Medicare Act for its postretirement plans under FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other than Pension until authoritative guidance on accounting for the federal subsidy is issued or until a significant event occurs that would require remeasurement of the plans' assets and obligations. The Company anticipates that the benefits it pays after 2006 will be lower as a result of the Medicare Act; however, the retiree medical obligations and costs reported in Note 2 to the financial statements do not reflect these changes. The final accounting guidance could require changes to previously reported information.
In May 2002, the GPSC approved a $7.8 million base rate increase to recover expenses related to a new purchased power agreement and other operation and maintenance expenses and approved an authorized return on equity of 12.0 percent. At the same time, the GPSC also approved a $44.3 million fuel cost recovery reduction. All customers saw a net rate decrease effective June 2002. In 2002, the Company filed a request and received an accounting order to defer until May 2005 approximately $3.8 million annually in Plant Wansley purchased power costs, which the GPSC had ruled to be outside of the test period in the Company's base rate order. Under the terms of the order, two-thirds of any earnings of the Company in a calendar year above a 12 percent return on common equity will be used to amortize the deferred amounts to expense. The remaining one-third of any such earnings can be retained by the Company. The accounting order provides the Company with discretionary authority to amortize up to an additional $1.5 million annually. In January 2003, the Company began deferring the costs under the terms of the accounting order. Through December 2003, the Company has amortized $3.7 million of the $3.8 million deferred. The deferred costs are included in other deferred debits in the Balance Sheets. The Company anticipates filing a base rate case in late 2004.
Prior to the 2002 base rate case order, the Company had been operating under a four-year accounting order approved by the GPSC. See Note 3 to the financial statements under "Retail Regulatory Matters" for additional information.
The Company is involved in various matters being litigated and regulatory matters that could affect future earnings. See Note 3 to the financial statements for information regarding material issues.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2003 Annual Report
ACCOUNTING POLICIES - -------------------
Application of Critical Accounting Policies and Estimates
The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has discussed the development and selection of the critical accounting policies and estimates described below with the Control and Compliance Committee of the Company's Board of Directors and the Audit Committee of Southern Company's Board of Directors.
Electric Utility Regulation
The Company is subject to retail regulation by the GPSC 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. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of Statement No. 71 has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and post-retirement 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. However, adverse legislation and 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" 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:
o 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. o Changes in existing income tax regulations or changes in Internal Revenue Service interpretations of existing regulations. o 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. o Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant. o Resolution or progression of existing matters through the legislative process, the court systems, or the EPA.
New Accounting Standards
Prior to January 2003, the Company accrued for the ultimate cost of retiring most long-lived assets over the life of the related asset through depreciation expense. FASB Statement No. 143, Accounting for Asset Retirement Obligations,
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established new accounting and reporting standards for legal obligations associated with the ultimate cost of retiring long-lived assets. 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. Additionally, non-regulated companies are no longer permitted to continue accruing future retirement costs for long-lived assets that they do not have a legal obligation to retire. For more information regarding the impact of adopting this standard effective January 1, 2003, see Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal."
FASB Statement No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, which further amends and clarifies the accounting and reporting for derivative instruments, became effective generally for financial instruments entered into or modified after June 30, 2003. Current interpretations of Statement No. 149 indicate that certain electricity forward transactions subject to unplanned netting -- including those typically referred to as "book outs" -- may only qualify as cash flow hedges if an entity can demonstrate that physical delivery or receipt of power occurred. The Company's forward electricity contracts continue to be exempt from fair value accounting requirements or to qualify as cash flow hedges, with the related gains and losses deferred in other comprehensive income. The implementation of Statement No. 149 did not have a material effect on the Company's financial statements.
In July 2003, the Emerging Issues Task Force (EITF) of FASB issued EITF No. 03-11, which became effective on October 1, 2003. The standard addresses the reporting of realized gains and losses on derivative instruments and is being interpreted to require book outs to be recorded on a net basis in operating revenues. Adoption of this standard did not have a material impact on the Company's financial statements.
FASB Interpretation No. 46, Consolidation of Variable Interest Entities, which was originally issued in January 2003, requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. In December 2003, the FASB revised Interpretation No. 46 and deferred the effective date until March 31, 2004, for interests held in variable interest entities or potential variable interest entities other than special purpose entities.
Current analysis indicates that any trust established by the Company to issue preferred securities is a variable interest entity under Interpretation No. 46, and that the Company is not the primary beneficiary of such a trust. If this conclusion is finalized, effective March 31, 2004, the investments in such trusts and loans from such trusts to the Company would be reflected as equity method investments and as long-term notes payable to affiliates, respectively, on the Balance Sheets. In January 2004, the Company redeemed all $40 million of its outstanding mandatorily redeemable preferred securities; thus the adoption of Interpretation No. 46 is not expected to have any impact on the Company's financial statements.
In May 2003, the FASB issued Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity, which requires classification of certain financial instruments within its scope, including shares that are mandatorily redeemable, as liabilities. Statement No. 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise on July 1, 2003. In accordance with Statement No. 150, mandatorily redeemable preferred securities are reflected as liabilities on the Balance Sheets. The adoption of Statement No. 150 had no impact on the Statements of Income and Cash Flows.
FINANCIAL CONDITION AND LIQUIDITY - ---------------------------------
Overview
As of December 31, 2003, the Company's capital structure consisted of 45.6 percent common stockholder's equity and 54.4 percent long-term debt, excluding amounts due within one year.
The principal change in the Company's financial condition in 2003 was the addition of $40.2 million to utility plant. The funds needed for gross property additions are currently provided from operating activities. See Statements of Cash Flows for additional information.
Sources of Capital
It is anticipated that the funds required for construction and other purposes, including compliance with environmental regulations, will be derived from
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sources similar to those used in the past including both internal and external funds. Historically, the external funding came from the issuance of debt and mandatorily redeemable preferred securities. Recently, the Company's debt financings have consisted of unsecured debt. The Company is required to meet certain earnings coverage requirements specified in its mortgage indenture and corporate charter to issue new first mortgage bonds and preferred stock. The Company's coverage ratios are sufficiently high to permit, at present interest rate levels, any foreseeable security sales. There are no restrictions on the amount of unsecured indebtedness allowed. The amount of securities which the Company will be permitted to issue in the future will depend upon market conditions and other factors prevailing at that time. Authorization for long-term financings is required by the GPSC. Currently, the Company has $75 million available under GPSC long-term financing authority expiring December 31, 2005.
As shown in the chart below, at the beginning of 2004, the Company had $60 million of unused short-term and revolving credit arrangements with banks to meet its short-term cash needs and to provide additional interim funding for the Company's construction program. The Company also has adequate cash flow from operating activities and access to the capital markets to meet liquidity needs.
At the beginning of 2004, bank credit arrangements are as follows:
Expires ------------------------- 2005 & Total Unused 2004 Beyond - -------------------------------------------------------------- (in millions) $80 $60 $40 $20
For additional information, see Note 6 to the financial statements under "Bank Credit Arrangements."
The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other Southern Company retail operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other operating company. The obligations of each company under these arrangements are several; there is no cross affiliate credit support. At December 31, 2003, the Company had no commercial paper and no outstanding extendible commercial notes.
The Company's committed credit arrangements provide liquidity support to the Company's variable rate obligations and to its commercial paper program. At December 31, 2003, the amount of variable rate obligations outstanding requiring liquidity support was $7.7 million.
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. In accordance with the Public Utility Holding Company Act, most loans between affiliated companies must be approved in advance by the Securities and Exchange Commission (SEC).
Financing Activities
Maturities and retirements of long-term debt were $39.4 million in 2003, $53.6 million in 2002, and $50.7 million in 2001.
In May 2003, the Company retired its $20 million Series B 5.12% Senior Notes due in 2003. In December 2003, the Company issued $25 million of Series E 4.90% Senior Notes maturing in 2013 and $35 million of Series F 5.50% Senior Notes maturing in 2028. The Company used the proceeds from these two sales to repay in December 2003 $5 million under a $30 million variable rate revolving credit agreement of which the Company had borrowed $25 million, to redeem in January 2004 $40 million of Savannah Electric Capital Trust I 6.85% Trust Preferred Securities, to repay a portion of its outstanding short-term indebtedness, and for other general corporate purposes.
In February 2003, the Company refinanced $13.9 million in pollution control bonds from a daily variable interest rate to an auction rate mode.
Credit Rating Risk
The Company does not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
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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 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.
To mitigate exposure to interest rates, the Company has entered into interest rate swaps that have been designated as cash flow hedges. The weighted average rate on variable rate long-term debt outstanding that has not been hedged at December 31, 2003 was 1.1 percent. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $0.2 million at December 31, 2003. The Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term. 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. In addition, the Company has implemented a natural gas/oil hedging program ordered by the GPSC. The program has negative financial hedge limits. In terms of dollar amounts, negative financial hedging positions, recoverable through the fuel clause, are limited to an above market cap equal to 10 percent of the Company's annual natural gas/oil budget. These hedging position limits were $1.5 million for 2001, $2.4 million for 2002, and $1.1 million for 2003 and will be $2.7 million for 2004. The program has operated within the defined hedging position limits set for each year.
The fair value of changes in energy related derivative contracts and year-end valuations were as follows at December 31:
Changes in Fair Value - ----------------------------------------------------------------- 2003 2002 - ----------------------------------------------------------------- (in thousands) Contracts beginning of year $ 626 $(1,053) Contracts realized or settled (1,798) 269 New contracts at inception - - Changes in valuation techniques - - Current period changes 1,635 1,410 - ----------------------------------------------------------------- Contracts end of year $ 463 $ 626 =================================================================
Source of 2003 Year-End Valuation Prices - ------------------------------------------------------------------ Total Maturity ------------------------ Fair Value Year 1 2-3 Years - ------------------------------------------------------------------ (in thousands) - ------------------------------------------------------------------ Actively quoted $463 $529 $(66) External sources - - - Models and other methods - - - - ------------------------------------------------------------------ Contracts end of year $463 $529 $(66) ==================================================================
Unrealized gains and losses from mark to market adjustments on derivative contracts related to the Company's fuel hedging program are recorded as regulatory assets and liabilities. Realized gains and losses from this program are included in fuel expense and recovered through the Company's FCR clause. Of the net gains, the Company is allowed to retain 25 percent in earnings. Gains and losses on derivative contracts that are not designated as hedges are recognized in the Statements of Income as incurred. For the years ended December 31, 2003, 2002, and 2001, these amounts were not material. At December 31, 2003, the fair value of derivative energy contracts was reflected in the financial statements as follows:
Amounts - ---------------------------------------------------------------- (in thousands) Regulatory liabilities, net $462 Other comprehensive income - Net income 1 - ---------------------------------------------------------------- Total fair value $463 ================================================================
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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 Company's construction program is currently estimated to be $51.8 million in 2004, $42.6 million in 2005, and $41.3 million in 2006. Environmental expenditures included in these amounts are $3.3 million, $1.4 million, and $3.0 million for 2004, 2005, and 2006, respectively. Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Construction of new transmission and distribution facilities and capital improvements for generation, transmission, and distribution facilities, including those needed to meet the environmental standards previously discussed, will be ongoing.
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 GPSC.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt and preferred securities, as well as the related interest and distributions, 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) Savannah Electric and Power Company 2003 Annual Report
Cautionary Statement Regarding Forward-Looking Information
The Company's 2003 Annual Report includes forward-looking statements in addition to historical information. Forward-looking information includes, among other things, statements concerning the estimated construction and other expenditures and the Company's projections for energy sales and postretirement benefit trust contributions. 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 comparable terminology. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include: o 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 and also changes in environmental, tax, and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations; o current and future litigation, regulatory investigations, proceedings or inquiries, including the pending EPA civil action against the Company; o the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates; o the impact of fluctuations in commodity prices, interest rates, and customer demand; o available sources and costs of fuels; o ability to control costs; o investment performance of the Company's employee benefit plans; o advances in technology; o state and federal rate regulations and pending and future rate cases and negotiations; o effects of and changes in political, legal, and economic conditions and developments in the United States, including the current soft economy; o internal restructuring or other restructuring options that may be pursued; o potential business strategies, including acquisitions or dispositions of assets, which cannot be assured to be completed or beneficial to the Company; o the ability of counterparties of the Company to make payments as and when due; o the ability to obtain new short- and long-term contracts with neighboring utilities; o the direct or indirect effects on the Company's business resulting from the terrorist incidents on September 11, 2001, or any similar incidents or responses to such incidents; o financial market conditions and the results of financing efforts, including the Company's credit ratings; o the ability of the Company to obtain additional generating capacity at competitive prices; o weather and other natural phenomena; o the direct or indirect effects on the Company's business resulting from the August 2003 power outage in the Northeast, or any similar incidents; o the effect of accounting pronouncements issued periodically by standard-setting bodies; and o other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed from time to time by the Company with the SEC.
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NOTES TO FINANCIAL STATEMENTS Savannah Electric and Power Company 2003 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Savannah Electric and Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of five retail operating companies, Southern Power Company (Southern Power), Southern Company Services (SCS), Southern Communications Services (Southern LINC), Southern Company Gas (Southern Company GAS), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The retail operating companies -- Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and the Company -- provide electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area of southeastern Georgia. Southern Power constructs, owns, and manages Southern Company's competitive generation assets and sells electricity at market-based rates in the wholesale market. Contracts among the retail operating companies and Southern Power--related to jointly owned generating facilities, interconnecting transmission lines, or the exchange of electric power--are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission (SEC). SCS, the system service company, provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern Company GAS is a competitive retail natural gas marketer serving customers in Georgia. Southern Holdings is an intermediate holding subsidiary for Southern Company's investments in synthetic fuels and leveraged leases and an energy services business. Southern Nuclear operates and provides services to Southern Company's nuclear power plants.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries, including the Company, are subject to the regulatory provisions of the PUHCA. The Company also is subject to regulation by the FERC and the Georgia Public Service Commission (GPSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by the GPSC. 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.
Certain prior years' data presented in the financial statements has been reclassified to conform with the current year presentation.
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 employee benefits, human resources, systems and procedures, and other administrative services with respect to business and operations and power pool operations. Costs for these services amounted to $16.3 million, $15.6 million, and $15.0 million during 2003, 2002, and 2001, respectively. Cost allocation methodologies used by SCS are approved by the SEC and management believes they are reasonable.
The Company has entered into a purchased power agreement with Southern Power for 200 megawatts of capacity from Plant Wansley Units 6 and 7 which began operation in June 2002. Purchased power capacity and energy costs in 2003 amounted to $30.1 million. At December 31, 2003, approximately $1.5 million in prepaid capacity expense related to this agreement was recorded in other deferred debits in the Balance Sheets.
In June 2002, the Company entered into another purchased power agreement with Southern Power for 200 megawatts of capacity from a planned combined-cycle plant at Plant McIntosh to be built and owned by Southern Power. This agreement will be effective in June 2005 and the annual capacity cost is expected to be approximately $15.0 million through June 2020. See Note 3 under "FERC Hearings" and Note 7 under "Purchased Power Commitments" for additional information.
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NOTES (continued) Savannah Electric and Power Company 2003 Annual Report
In March 2003, the Company transferred to Southern Power 58 acres of land to facilitate construction at Plant McIntosh. The transfer was made at the Company's book value of approximately $16,500 in accordance with PUHCA and the related SEC order (Release No. 35-27322) dated December 27, 2000, which authorized the formation of Southern Power and the transfer of assets thereto. On July 17, 2003, the GPSC issued an order requiring that the Company record the transfer of this land at the higher of net book value or fair market value based on an appraisal by an appraiser selected by the GPSC staff. Based on the appraisal completed in September 2003, the fair market value of the land was established at $320,000.
The Company operates an eight-unit combustion turbine site at its Plant McIntosh. Two of the units are owned by the Company, and six of the units are owned by Georgia Power. Georgia Power reimburses the Company for its proportionate share of the related expenses, which were $3.6 million in 2003 and $1.8 million in 2002. See Note 4 under "Joint Ownership Agreements" for additional information.
The retail operating companies, including the Company, Southern Power, and Southern Company GAS 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" and "Purchased Power Commitments" for additional information.
Revenues and Fuel Costs
Revenues are recognized as services are rendered. Unbilled revenues are accrued at the end of each fiscal period. Fuel costs are expensed as the fuel is used. 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 recoverable fuel costs and amounts actually recovered in current regulated rates.
The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts averaged less than 1 percent of revenues.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal investment tax credits utilized are deferred and amortized to income over the average lives of the related property.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues to the Company 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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Regulatory assets and (liabilities) reflected in the Balance Sheets at December 31 and the amortization periods are discussed below as follows:
2003 2002 Note ------------------------------ (in thousands) Asset retirement obligations $ 3,265 $ - (a) Deferred income tax charges 9,611 11,692 (a) Loss on reacquired debt 7,488 8,103 (b) Deferred McIntosh maintenance costs 9,818 5,790 (c) Wansley accounting order 162 - (d) Other cost of removal obligations (36,843) (31,884) (a) Fuel-hedging liabilities (462) (621) (e) Deferred income tax credits (9,804) (12,445) (a) Storm damage reserves (7,103) (5,603) (d) Accelerated cost recovery (4,269) (7,282) (f) Property damages reserves (1,098) (750) (g) Injuries and damages reserves (91) (250) (g) - ------------------------------------------------------- Total $(29,326) $(33,250) ======================================================= 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 either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 35 years. (c) Amortized over 10 years ending in 2011. (d) Recorded and recovered or amortized as approved by the GPSC. (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, costs are recovered through the fuel cost recovery clauses. (f) Amortized over three-year period ending in May 2005. (g) Recorded and relieved upon the occurrence of a loss.
In the event that a portion of the Company's operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair value. All regulatory assets and liabilities are to be reflected in rates.
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 2.9 percent in 2003, 2.9 percent in 2002, and 3.0 percent in 2001. 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 accumulated depreciation. 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 certain facilities. In 2002 and 2001, the Company recorded accelerated depreciation of $1.0 million and $2.5 million, respectively, in accordance with the GPSC's 1998 accounting order. In the 2002 base rate order, the GPSC ordered the Company to amortize the balance of accelerated cost recovery as a credit to depreciation expense over a three year period beginning June 2002. Accordingly, in 2003 and 2002, the Company amortized $3.0 million and $1.8 million, respectively. See Note 3 under "Retail Regulatory Matters" for additional information.
Asset Retirement Obligations and Other Costs of Removal
In accordance with regulatory requirements, prior to January 2003, the Company followed the industry practice of accruing for the ultimate cost of retiring most long-lived assets over the life of the related asset as part of the annual depreciation expense provision. In accordance with SEC requirements, such amounts are reflected on the Balance Sheet as regulatory liabilities. Effective January 1, 2003, the Company adopted FASB Statement No. 143, Accounting for Asset Retirement Obligations. Statement No. 143 establishes new accounting and reporting standards for legal obligations associated with the ultimate costs of retiring long-lived assets. The present value of the ultimate costs for an asset's future retirement must be recorded in the period in which the liability is incurred. The costs must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Additionally, Statement No. 143 does not permit the continued accrual of future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. However, the Company has received guidance regarding accounting for the financial statement impacts of Statement No. 143 from the GPSC and will continue to recognize the accumulated removal costs for other obligations as a regulatory
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liability included in accumulated depreciation. Therefore, the Company had no cumulative effect to net income resulting from the adoption of Statement No. 143.
The Company has retirement obligations related to various landfill sites, ash ponds, a rail line, and underground storage tanks. The Company has also identified retirement obligations related to certain transmission and distribution facilities. However, liabilities for the removal of these transmission and distribution assets have not been recorded because no reasonable estimate can be made regarding the timing of the obligations. The Company will continue to recognize in the income statement allowed removal costs in accordance with its regulatory treatment. Any difference between costs recognized under Statement No. 143 and those reflected in rates are recognized as either a regulatory asset or liability and are reflected in the Balance Sheets.
Details of the asset retirement obligations included in the Balance Sheets are as follows:
- ---------------------------------------------------------------- (in thousands) Balance beginning of year $ - Liabilities incurred 4,020 Liabilities settled (11) Accretion 211 Cash flow revisions - - ---------------------------------------------------------------- Balance end of year $4,220 ================================================================
If Statement No. 143 had been adopted on January 1, 2002, the pro-forma asset retirement obligations would have been $2.7 million.
Allowance for Funds Used During Construction (AFUDC)
In accordance with regulatory treatment, the Company records AFUDC. AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new 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 composite rates used by the Company to calculate AFUDC were 4.22 percent in 2003, 2.82 percent in 2002, and 5.13 percent in 2001. AFUDC as a percent of net income was 1.4 percent in 2003, 0.4 percent in 2002, and 0.8 percent in 2001.
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 AFUDC. 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. In accordance with the 2002 base rate order, the Company is deferring the costs of certain significant maintenance costs for the combustion turbines at Plant McIntosh and amortizing such costs over 10 years, which approximates the expected maintenance cycle.
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 provision for loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment provision is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
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.
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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. The Company accounts for its stock-based compensation plans in accordance with Accounting Principles Board Opinion No. 25. Accordingly, no compensation expense has been recognized because the exercise price of all options granted equaled the fair-market value on the date of grant. When options are exercised the Company receives a capital contribution from Southern Company equivalent to the related income tax benefit.
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 or regulatory assets or liabilities as appropriate 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 has implemented a natural gas/oil hedging program as ordered by the GPSC. The program has negative financial hedge limits. In terms of dollar amounts, negative financial hedging positions, recoverable through the fuel clause, are limited to an above market cap equal to 10 percent of the Company's annual natural gas/oil budget. These hedging position limits were $1.5 million for 2001, $2.4 million for 2002, and $1.1 million for 2003 and will be $2.7 million for 2004. The program has operated within the defined hedging position limits set for each year.
The Company's other financial instruments for which the carrying amount does not equal fair value at December 31 were as follows:
Carrying Fair Amount Value -------------------------- (in millions) Long-term debt: At December 31, 2003 $218 $220 At December 31, 2002 $183 $187
The fair values for long-term debt 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 changes in additional minimum pension liability, net of income taxes.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, non-contributory pension plan that covers substantially all employees. The plan is funded in accordance with Employee Retirement Income Security Act (ERISA) requirements. The Company also provides certain non-qualified benefit plans for a selected group of management and highly compensated employees and directors. Benefits under these non-qualified plans are funded on a cash basis. In addition, the Company has a supplemental retirement plan for certain executive employees. The plan is unfunded and payable from the general funds of the Company. The Company has purchased life insurance on participating executives and plans to use these policies to satisfy this obligation. Also, the Company provides certain medical care and life insurance benefits for retired employees. The Company funds trusts to the extent required by the GPSC and the FERC. For the year ended December 31,
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2004, postretirement benefit contributions are expected to total approximately $1.9 million.
The measurement date for plan assets and obligations is September 30 for each year. In 2002, the Company adopted several plan changes that had the effect of increasing benefits to both current and future retirees.
Pension Plans
The accumulated benefit obligation for the pension plans was $87.2 million in 2003 and $76.6 million in 2002. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:
Projected Benefit Obligations --------------------------- 2003 2002 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $85,262 $79,550 Service cost 2,175 2,204 Interest cost 5,409 5,811 Benefits paid (4,425) (4,213) Actuarial loss and employee transfers 6,137 1,793 Amendments 231 117 - --------------------------------------------------------------- Balance at end of year $94,789 $85,262 ===============================================================
Plan Assets --------------------------- 2003 2002 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $44,092 $50,858 Actual return on plan assets 6,829 (2,720) Benefits paid (3,909) (3,734) Employee transfers 478 (312) - --------------------------------------------------------------- Balance at end of year $47,490 $44,092 ===============================================================
Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Service (IRS) revenue code. The Company's investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.
Plan assets were invested as follows:
Plan Assets -------------------------------- Target 2003 2002 - ---------------------------------------------------------------- Domestic equity 37% 37% 35% International equity 20 20 18 Global fixed income 26 24 25 Real estate 10 11 12 Private equity 7 8 10 - ---------------------------------------------------------------- Total 100% 100% 100% ================================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
2003 2002 - --------------------------------------------------------------- (in thousands) Funded status $(47,299) $(41,170) Unrecognized prior service cost 7,258 6,847 Unrecognized net loss 23,379 21,432 - --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $(16,662) $(12,891) ===============================================================
In 2003 and 2002, amounts recognized in the Balance Sheets for accumulated other comprehensive income and intangible assets to record the minimum pension liability related to the non-qualified plans were $2.9 million and $1.5 million and $2.0 million and $1.5 million, respectively.
Components of the pension plans' net periodic cost were as follows:
2003 2002 2001 - ----------------------------------------------------------------- (in thousands) Service cost $ 2,175 $ 2,204 $ 2,074 Interest cost 5,409 5,811 5,426 Expected return on plan assets (4,186) (4,311) (4,215) Recognized net loss 152 54 16 Net amortization 740 672 700 - ----------------------------------------------------------------- Net pension cost $ 4,290 $ 4,430 $ 4,001 =================================================================
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Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:
Accumulated Benefit Obligations --------------------------- 2003 2002 - ---------------------------------------------------------------- (in thousands) Balance at beginning of year $32,702 $28,121 Service cost 493 431 Interest cost 2,082 2,065 Benefits paid (1,319) (1,160) Actuarial loss (gain) and employee transfers 3,291 3,245 - --------------------------------------------------------------- Balance at end of year $37,249 $32,702 ===============================================================
Plan Assets --------------------------- 2003 2002 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $7,994 $7,401 Actual return on plan assets 1,481 (732) Employer contributions 3,119 2,485 Benefits paid (1,319) (1,160) - --------------------------------------------------------------- Balance at end of year $11,275 $7,994 ===============================================================
Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the IRS revenue code. The Company's investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.
Plan assets were invested as follows:
Plan Assets -------------------------------- Target 2003 2002 - ---------------------------------------------------------------- Domestic equity 52% 51% 44% International equity 11 14 15 Global fixed income 33 30 34 Real estate 2 3 4 Private equity 2 2 3 - ---------------------------------------------------------------- Total 100% 100% 100% ================================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows:
2003 2002 - --------------------------------------------------------------- (in thousands) Funded status $(25,974) $(24,708) Unrecognized transition obligation 4,444 4,938 Unamortized prior service cost 4,167 4,429 Unrecognized net loss 8,886 6,435 Fourth quarter contributions 1,063 2,104 - --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $(7,414) $(6,802) ===============================================================
Components of the postretirement plan's net periodic cost were as follows:
2003 2002 2001 - ---------------------------------------------------------------- (in thousands) Service cost $ 493 $ 431 $ 433 Interest cost 2,082 2,065 2,022 Expected return on plan assets (732) (627) (555) Recognized net loss 91 - - Net amortization 756 756 731 - ---------------------------------------------------------------- Net postretirement cost $2,690 $2,625 $2,631 ================================================================
The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations and the net periodic costs for the pension and postretirement benefit plans were as follows:
2003 2002 2001 - ----------------------------------------------------------------- Discount 6.00% 6.50% 7.50% Annual salary increase 3.75 4.00 5.00 Long-term return on plan assets 8.50 8.50 8.50 - -----------------------------------------------------------------
The Company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.
An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 8.25 percent for 2003, decreasing gradually to 5.25 percent through the year 2010 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated
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benefit obligation and the service and interest cost components at December 31, 2003 as follows:
1 Percent 1 Percent Increase Decrease - --------------------------------------------------------------- (in thousands) Benefit obligation $2,437 $2,209 Service and interest costs 158 142 ===============================================================
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee's base salary. Total matching contributions made to the plan for the years 2003, 2002, and 2001 were $1.1 million, $1.0 million, and $1.0 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, and citizen enforcement of environmental requirements, 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 litigation against the Company cannot be predicted at this time; however, 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.
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 Alabama Power, Georgia Power, and SCS. The complaint alleged violations of the New Source Review (NSR) provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia and violations of related state laws. The civil action requested penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued to the retail operating companies, notices of violation relating to 10 generating facilities, which include the five facilities mentioned previously and the Company's Plant Kraft. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notices of violation and to add Gulf Power, Mississippi Power, and the Company as defendants.
In August 2000, the U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and granted SCS' motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. In March 2001, the court granted the EPA's motion to add the Company as a defendant, but it denied the motion to add Gulf Power and Mississippi Power based on lack of jurisdiction in Georgia over those companies. As directed by the court, the EPA refiled its amended complaint limiting claims to those brought against Georgia Power and the Company. In addition, the EPA refiled its claims against Alabama Power in the U.S. District Court for the Northern District of Alabama. These complaints allege violations with respect to eight coal-fired generating facilities in Alabama and Georgia, and they request the same kinds of relief as was requested in the original complaint, i.e. penalties and injunctive relief, including installation of the best available control technology. The EPA has not refiled against Gulf Power, Mississippi Power, or SCS.
The actions against Alabama Power, Georgia Power, and the Company were stayed in the spring of 2001 during the appeal of a very similar NSR enforcement action against the Tennessee Valley Authority (TVA) before the U.S. Court of Appeals for the Eleventh Circuit. The TVA appeal involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and the Company. Because the final resolution of the TVA appeal could have a significant impact on Alabama Power and Georgia Power, both companies have been involved in that appeal. On June 24, 2003, the court of appeals issued its ruling in the TVA case. It found unconstitutional the statutory scheme set forth in the Clean Air Act that allowed the EPA to impose penalties for failing to comply with an administrative compliance order, like the one issued to TVA, without the EPA having to prove the underlying violation. Thus, the court of appeals held that
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the compliance order was of no legal consequence, and TVA was free to ignore it. The court did not, however, rule directly on the substantive legal issues about the proper interpretation and application of certain NSR provisions that had been raised in the TVA appeal. On September 16, 2003, the court of appeals denied the EPA's request for a rehearing of the decision. On February 13, 2004, the EPA petitioned the U.S. Supreme Court to review the decision of the court of appeals. The EPA also filed a motion to lift the stay in the action against Alabama Power. At this time, no party to the Georgia Power and Savannah Electric action, which was administratively closed two years ago, has asked the court to reopen that case.
Since the inception of the NSR proceedings against Georgia Power, Alabama Power, and the Company, the EPA has also been proceeding with similar NSR enforcement actions against other utilities, involving many of the same legal issues. In each case, the EPA alleged that the utilities failed to comply with the NSR permitting requirements when performing maintenance and construction activities at coal-burning plants, which activities the utilities considered to be routine or otherwise not subject to NSR. In 2003, district courts addressing these cases issued opinions that reached conflicting conclusions.
In October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act clarifying the scope of the existing Routine Maintenance, Repair, and Replacement exclusion. On December 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit stayed the effectiveness of these revisions pending resolution of related litigation. In January 2004, the Bush Administration announced that it would continue to enforce the existing rules.
The Company believes that it complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome in this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
Right of Way Litigation
In late 2001, certain subsidiaries of Southern Company, including Alabama Power, Georgia Power, Gulf Power, Mississippi Power, the Company, and Southern Telecom (collectively, defendants), 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 the telecommunications company in pending and future right of way litigation. The Company believes that the plaintiff's claims are without merit. 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
The Company filed a base rate case in November 2001 to recover significant new expenses related to the 200 megawatt Plant Wansley purchased power agreement which began in June 2002, as well as other operation and maintenance expense changes. In early 2002, the Company filed for a fuel cost recovery decrease. In May 2002, the GPSC approved a $7.8 million base rate increase and an authorized return on equity of 12.0 percent. At the same time, the GPSC also approved a $44.3 million fuel cost recovery reduction. As a result of these two rate changes, all customers saw a net rate decrease effective June 2002. In December 2002, at the Company's request, the GPSC issued an accounting order authorizing the Company to defer until May 2005 approximately $3.8 million annually in Plant Wansley purchased power costs that the GPSC had ruled to be outside the test period for the base rate order. Under the terms of the order, two-thirds of any earnings of the Company in a calendar year above a 12 percent return on common equity will be used to amortize the deferred amounts to purchase power expense. The remaining one-third of any such earnings can be retained by the Company. The Company has the discretionary authority to amortize up to an additional $1.5 million annually. In January 2003, the Company began deferring the costs under the terms of the accounting order. Through December 2003, the Company amortized
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$3.7 million of the $3.8 million deferred. The Company anticipates filing a base rate case in late 2004.
Prior to the 2002 base rate order, the Company had been operating under a four-year accounting order approved by the GPSC. Under this order, the Company reduced the electric rates of its small business customers by approximately $11 million over four years. The Company also expensed an additional $1.95 million in storm damage accruals and accrued an additional $8 million in depreciation on generating assets over the term of the order. The additional depreciation accumulated in a regulatory liability account. Under the 2002 rate order, the accumulated accelerated depreciation is being amortized equally over three years as a credit to expense beginning June 1, 2002. At this time, the Company also discontinued recording accelerated depreciation. In addition, the Company had discretionary authority to provide up to an additional $0.3 million per year in storm damage accruals and up to an additional $4.0 million in depreciation expense over the four years. Total storm damages accrued under the order were $0.5 million in 2002 and $1.5 million in 2001. Under the 2002 rate order, the Company's annual storm damage accrual level was set at $1.5 million. The Company accrued $1.5 million in 2003 and $0.9 million in 2002 to the accumulated provision for storm damage.
FERC Matters
The Company has obtained FERC approval to sell power to nonaffiliates at market-based prices under specific contracts. Through SCS as agent, the Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities' applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company's retail operating companies, and found them to be "pivotal suppliers" in their control area market and ordered the implementation of several mitigation measures. SCS, on behalf of the retail operating companies, sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. SCS, on behalf of the retail operating companies, submitted comments to the FERC in 2002 regarding these issues. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. The Company anticipates that the FERC will address the requests for rehearing in the near future. Regardless of the outcome of the SMA proposal, the FERC retains the ability to modify or withdraw the authorization for any seller to sell at market-based rates, if it determines that the underlying conditions for having such authority are no longer applicable. The final outcome of this matter will depend on the form in which the SMA test and mitigation measures rules may be ultimately adopted and cannot be determined at this time.
Purchased power agreements (PPAs) by Georgia Power and the Company for Southern Power's Plant McIntosh capacity were certified by the GPSC in December 2002 after a competitive bidding process. In April 2003, Southern Power applied for FERC approval of these PPAs. Interveners opposed the FERC's acceptance of the PPAs, alleging that the PPAs do not meet the applicable standards for market-based rates between affiliates. In July 2003, the FERC accepted the PPAs to become effective as scheduled on June 1, 2005, subject to refund, and ordered that hearings be held to determine: (a) whether, in the design and implementation of the GPSC competitive bidding process, Georgia Power and the Company unduly preferred Southern Power; (b) whether the analysis of the competitive bids unduly favored Southern Power, particularly with respect to evaluation of non-price factors; (c) whether Georgia Power and the Company selected their affiliate, Southern Power, based upon a reasonable combination of price and non-price factors; (d) whether Southern Power received an undue preference or competitive advantage in the competitive bidding process as a result of access to its affiliate's transmission system; (e) whether and to what extent the PPAs impact wholesale competition; and (f) whether the PPAs are just and reasonable and not unduly discriminatory. Hearings are scheduled to begin in March 2004. Management believes that the PPAs should be approved by the FERC; however, the ultimate outcome of this matter cannot now be determined.
4. JOINT OWNERSHIP AGREEMENTS
The Company operates and jointly owns its Plant McIntosh combustion turbines with Georgia Power. Two of the eight units are owned by the Company, and six units are owned by Georgia Power. The Company's amount of investment in Plant McIntosh combustion turbines and related accumulated depreciation at December 31, 2003 were $53 million and $13 million, respectively. The Company's
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proportionate share of its combustion turbine 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. In 2002, Southern Company began filing a combined State of Georgia income tax return. Under a joint consolidated income tax 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.
At December 31, 2003, tax-related regulatory assets and liabilities were $9.6 million and $9.8 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.
Details of income tax provisions are as follows:
2003 2002 2001 -------------------------------- (in thousands) Total provision for income taxes Federal -- Currently payable $11,725 $17,089 $27,991 Deferred 1,299 (5,660) (17,951) - ------------------------------------------------------------------ 13,024 11,429 10,040 - ------------------------------------------------------------------ State -- Currently payable 2,730 1,572 4,282 Deferred (646) (568) (2,577) - ------------------------------------------------------------------ 2,084 1,004 1,705 - ------------------------------------------------------------------ Total $15,108 $12,433 $11,745 ==================================================================
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:
2003 2002 --------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $88,332 $83,092 Property basis differences (1,640) (1,250) Other 2,696 3,630 - ------------------------------------------------------------------ Total 89,388 85,472 - ------------------------------------------------------------------ Deferred tax assets: Pension and other benefits 15,671 12,792 Other 14,284 14,132 - ------------------------------------------------------------------ Total 29,955 26,924 - ------------------------------------------------------------------ Total deferred tax liabilities, net 59,433 58,548 Portion included in current assets, net 24,419 20,422 - ------------------------------------------------------------------ Accumulated deferred income taxes in the Balance Sheets $83,852 $78,970 ==================================================================
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 $0.7 million per year in 2003, 2002, and 2001. At December 31, 2003, all investment tax credits available to reduce federal income taxes payable had been utilized.
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
2003 2002 2001 ---------------------------- Federal statutory tax rate 35% 35% 35% State income tax, net of Federal income tax benefit 4 2 3 Other 1 (2) (3) ---------------------------------------------------------------- Effective income tax rate 40% 35% 35% ================================================================
6. FINANCING
Mandatorily Redeemable Preferred Securities
The Company formed a wholly owned trust subsidiary for the purpose of issuing $40 million 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 totaling $41.2 million, which constitute substantially all of the assets of the trust. The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the trust's payment obligations with respect to these securities.
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In January 2004, all preferred securities issued by the trust were redeemed at par; therefore at December 31, 2003, they were included on the Balance Sheets in Securities Due Within One Year.
Long-Term Debt and Capital Leases
The Company's Indenture related to its First Mortgage Bonds is unlimited as to the authorized amount of bonds which may be issued, provided that required property additions, earnings, and other provisions of such Indenture are met.
Assets acquired under capital leases are recorded as utility plant in service, and the related obligation is classified as other long-term debt. Leases are capitalized at the net present value of the future lease payments. However, for ratemaking purposes, these obligations are treated as operating leases and, as such, lease payments are charged to expense as incurred.
Long-Term Debt Due Within One Year
A summary of the sinking fund requirements and scheduled maturities and redemptions of long-term debt due within one year at December 31 is as follows:
2003 2002 ---------------------- (in thousands) Bond sinking fund requirement $ 200 $ 200 Less: Portion to be satisfied by certifying property additions 200 200 - ------------------------------------------------------------------- Cash sinking fund requirement - - Mandatorily redeemable preferred securities 40,000 - Other long-term debt maturities 910 20,892 - ------------------------------------------------------------------- Total $40,910 $20,892 ===================================================================
The first mortgage bond improvement (sinking) fund requirements amount to 1 percent of each outstanding series of bonds authenticated under the first mortgage bond indenture prior to January 1 of each year, other than those issued to collateralize pollution control and other obligations. The requirements may be satisfied by depositing cash or reacquiring bonds, or by pledging additional property equal to 1 2/3 times the requirements.
The sinking fund requirements of first mortgage bonds were satisfied by cash redemption in 2002 and by certifying property additions in 2003. The 2004 requirement will be satisfied by certifying property additions. Sinking fund requirements and/or maturities through 2008 applicable to long-term debt are as follows: $40.9 million in 2004; $20.8 million in 2005; $20.8 million in 2006; $0.7 million in 2007; and $45.8 million in 2008.
Assets Subject to Lien
As amended and supplemented, the Company's first mortgage bond indenture, which secures the first mortgage bonds issued by the Company, constitutes a direct first lien on substantially all of the Company's fixed property and franchises.
Bank Credit Arrangements
At the beginning of 2004, credit arrangements with banks totaled $80 million and expire at various times during 2004, 2005, and 2006. In September 2002, the Company borrowed $25 million under a $30 million variable rate revolving credit agreement that terminates in 2005. Of this amount, $5 million was repaid in December 2003.
In connection with these credit arrangements, the Company agrees to pay commitment fees based on the unused portions of the commitments. Commitment fees are less than 1/8 of 1 percent for the Company.
The credit arrangements contain covenants that limit the level of indebtedness to capitalization to 65 percent, as defined in the agreements. Exceeding these debt levels would result in a default under the credit arrangements. In addition, the credit arrangements contain cross default provisions that would be triggered 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. Borrowings under unused credit arrangements totaling $10 million would be prohibited if the Company experiences a material adverse change (as defined in such arrangements).
The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other Southern Company retail operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not
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commingled with proceeds from such issuances for the benefit of any other retail operating company. The obligations of each company under these arrangements are several; there is no cross affiliate credit support. At December 31, 2003, the Company had no commercial paper and no extendible commercial notes outstanding. During 2003, the peak amount of commercial paper outstanding was $32.8 million and the average amount outstanding was $9.1 million. The average annual interest rate on commercial paper was 1.13 percent.
The Company's committed credit arrangements provide liquidity support to the Company's variable rate obligations and to its commercial paper program. At December 31, 2003, the amount of variable rate obligations outstanding requiring liquidity support was $7.7 million.
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 GPSC. The Company also enters into hedges of forward electricity sales.
At December 31, 2003, the fair value of derivative energy contracts was reflected in the financial statements as follows:
Amounts - ---------------------------------------------------------------- (in thousands) Regulatory liabilities, net $462 Other comprehensive income - Net income 1 - ---------------------------------------------------------------- Total fair value $463 ================================================================
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 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 are generally structured to match the critical terms of the hedged debt instruments; therefore, no material ineffectiveness has been recorded in earnings.
At December 31, 2003, the Company had $20 million notional amount of interest rate swaps outstanding with net fair value losses of $0.1 million as follows:
Cash Flow Hedges
Weighted Average Fair Fixed Value Rate Notional Gain/ Maturity Paid Amount (Loss) - -------------------------------------------------------- (in millions) 2004 2.06% $20 $(0.1) - --------------------------------------------------------
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. For 2004, pre-tax losses of approximately $0.1 million are expected to be reclassified from other comprehensive income to interest expense.
Common Stock Dividend Restrictions
The Company's first mortgage bond indenture contains certain limitations on the payment of cash dividends on common stock. At December 31, 2003, approximately $68 million of retained earnings was restricted against the payment of cash dividends on common stock under the terms of the Indenture.
In accordance with the PUHCA, the Company is restricted from paying common dividends from paid-in capital without SEC approval
7. COMMITMENTS
Construction Program
The Company is engaged in a continuous construction program, currently estimated to total $51.8 million in 2004, $42.6 million in 2005, and $41.3 million in 2006. 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
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additional generating assets; revised load growth estimates; changes in environmental regulations; changes in FERC rules and transmission regulations; increasing costs of labor, equipment, and materials; and cost of capital. The Company does not have any generating plants under construction. However, construction related to new transmission and distribution facilities and capital improvements to existing generation, transmission, and distribution facilities, including those necessary to meet environmental standards, will continue. At December 31, 2003, significant purchase commitments were outstanding in connection with the construction program.
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the Company has entered into 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. In addition, SCS acts as agent for the Company, the other retail operating companies, Southern Power, and Southern Company GAS with regard to natural gas purchases. 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 New York Mercantile future prices at December 31, 2003. Total estimated minimum long-term obligations at December 31, 2003 were as follows:
Natural Year Gas Coal - ---- ------------------------------------- (in thousands) 2004 $ 867 $31,439 2005 8,651 - 2006 10,491 - 2007 7,620 - 2008 27,640 - 2009 and thereafter 284,097 - - --------------------------------------------------------------- Total commitments $339,366 $31,439 ===============================================================
Additional commitments for fuel will be required to supply the Company's future needs.
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company retail operating companies, Southern Power, and Southern Company GAS. Under these agreements, each of the retail operating companies, Southern Power, and Southern Company GAS may be jointly and severally liable. The creditworthiness of Southern Power and Southern Company GAS is currently inferior to the creditworthiness of the retail operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the retail operating companies to insure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power or Southern Company GAS as a contracting party under these agreements.
Purchased Power Commitments
The Company has entered into long-term commitments for the purchase of electricity from Southern Power. Estimated total long-term obligations at December 31, 2003 were as follows:
Year Commitments - ---- --------------- (in thousands) 2004 $ 13,221 2005 24,447 2006 27,343 2007 27,354 2008 27,366 2009 and thereafter 171,262 - --------------------------------------------------------------- Total commitments $290,993 ===============================================================
Operating Leases
The Company has rental agreements with various terms and expiration dates. Rental expenses totaled $0.9 million for 2003, $0.6 million for 2002, and $0.5 million for 2001. Of these amounts, $0.8 million in 2003, $0.5 million in 2002, and $0.4 million in 2001 related to railcar leases and coal dozers and were recoverable through the Company's fuel cost recovery clause.
At December 31, 2003, estimated future minimum lease payments for noncancelable operating leases were as follows:
Year Railcars Other Total - --------------------------------------------------------------- (in thousands) 2004 $ 429 $ 415 $ 844 2005 429 368 797 2006 429 331 760 2007 429 327 756 2008 429 306 735 2009 and thereafter 4,035 220 4,255 - --------------------------------------------------------------- Total minimum payments $6,180 $1,967 $8,147 ===============================================================
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8. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 2003 and 2002 are as follows (in thousands):
Operating Operating Net Quarter Ended Revenues Income Income - ----------------------------------------------------------------
March 2003 $68,875 $ 9,015 $ 3,509 June 2003 78,242 13,535 6,296 September 2003 99,115 25,584 14,378 December 2003 67,823 2,323 (1,376)
March 2002 $57,378 $ 6,865 $ 1,802 June 2002 78,360 14,594 7,035 September 2002 96,971 24,654 13,148 December 2002 66,843 4,701 895 - ----------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and a seasonal rate structure, among other factors.
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SOUTHERN POWER COMPANY
FINANCIAL SECTION
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MANAGEMENT'S REPORT Southern Power Company 2003 Annual Report
The management of Southern Power Company has prepared - and is responsible for - the financial statements and related information included in this report. These statements were prepared in accordance with accounting principles generally accepted in the United States and necessarily include amounts that are based on the best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that the accounting records reflect only authorized transactions of the Company. Limitations exist in any system of internal controls, however, based on a recognition that the cost of the system should not exceed its benefits. The Company believes its system of internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's internal accounting controls are evaluated on an ongoing basis by the Company's internal audit staff. The Company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements.
Southern Company's audit committee of its board of directors, composed of four independent directors, provides a broad overview of management's financial reporting and control functions. Periodically, this committee meets with management, the internal auditors and the independent public accountants to ensure that these groups are fulfilling their obligations and to discuss auditing, internal controls, and financial reporting matters. The internal auditors and independent public accountants have access to the members of the audit committee at any time.
Management believes that its policies and procedures provide reasonable assurance that the Company's operations are conducted according to a high standard of business ethics.
In management's opinion, the financial statements present fairly, in all material respects, the financial position, results of operations and cash flows of the Company in conformity with accounting principles generally accepted in the United States.
/s/William P. Bowers William P. Bowers President and Chief Executive Officer
/s/Cliff S. Thrasher Cliff S. Thrasher Senior Vice President, Comptroller and Chief Financial Officer March 1, 2004
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INDEPENDENT AUDITORS' REPORT
Southern Power Company:
We have audited the accompanying balance sheets of Southern Power Company (a wholly owned subsidiary of Southern Company) as of December 31, 2003 and 2002, and the related statements of income, comprehensive income, common stockholder's equity, and cash flows for the years then ended, and for the period from January 8, 2001 (inception) to December 31, 2001. These financial statements are the responsibility of Southern Power 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 auditing standards generally accepted in the United States of America. 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 financial statements (pages II-299 through II-312) present fairly, in all material respects, the financial position of Southern Power Company at December 31, 2003 and 2002, and the results of its operations and its cash flows for the years then ended, and for the period from January 8, 2001 (inception) to December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.
/s/Deloitte & Touche LLP Atlanta, Georgia March 1, 2004
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Southern Power Company 2003 Annual Report
OVERVIEW OF EARNINGS AND BUSINESS - --------------------------------- ACTIVITIES - ----------
In January 2001, Southern Power Company was formed as a wholly-owned subsidiary of Southern Company and began commercial operations in August 2001.
Earnings
The Company's 2003 earnings totaled $155 million, representing a $101 million increase over 2002. The 2003 increase is attributed to increased sales of wholesale capacity and energy from units placed in service during 2003 (Plant Franklin Unit 2, Plant Harris Units 1 and 2 and Plant Stanton A) and to a one-time gain of $50 million recognized in May 2003 upon the termination of Dynegy, Inc.'s (Dynegy) obligations under Power Purchase Agreements (PPAs). The increased sales came from new PPAs with Alabama Power and Georgia Power as well as the marketing of uncontracted capacity. As future PPAs become effective, the amount of uncontracted capacity available for external sales will decline significantly. Additional factors contributing to the increased earnings were non-recurring energy sales transactions related to test period generation for units placed in service in June 2003, as well as manufacturer's tax credits from the State of Georgia related to construction of Plants Dahlberg and Wansley. As of December 31, 2003, the Company had approximately 4,775 megawatts in commercial operation compared to approximately 2,400 in commercial operation at December 31, 2002.
The Company's 2002 earnings totaled $54.3 million, representing a $46.1 million increase over 2001. The 2002 increase was the result of increased sales of wholesale capacity and energy to affiliated and non-affiliated companies. The increased sales resulted primarily from the initiation of PPAs with Georgia Power and Savannah Electric and requirements agreements with 11 electric municipal cooperatives (EMCs) that went into effect in June 2002. Earnings for 2002 also reflected commercial operation of Plant Wansley Units 6 and 7 and Plant Franklin Unit 1 that began in June 2002 and a full year of Plant Dahlberg operations.
The Company began significant operations in July 2001 when Plant Dahlberg was transferred from Georgia Power, another wholly-owned subsidiary of Southern Company. The Company's 2001 earnings totaled $8.2 million and were derived primarily from the sales of wholesale capacity and energy to affiliated and non-affiliated companies.
Business Activities
The Company constructs, owns, and manages Southern Company's competitive generating assets and sells electricity at market-based rates in the wholesale market.
Several factors affect the opportunities, challenges, and risks of the Company's competitive wholesale energy business. These factors include the ability to achieve energy sales growth while containing costs. Another major factor is federal regulatory policy, which may impact the Company's level of participation in this market. Future earnings for the business in the near term will depend, in part, upon completion of construction on new generating facilities, regulatory matters, including those related to affiliate contracts, energy sales, creditworthiness of customers, total generating capacity available in the Southeast, and the successful remarketing of capacity as current contracts expire.
RESULTS OF OPERATIONS - ---------------------
A condensed income statement is as follows:
Increase (Decrease) Amount From Prior Year --------------------------------------- 2003 2003 2002 - -------------------------------------------------------------------- (in thousands) Operating revenues $681,780 $383,012 $269,467 - -------------------------------------------------------------------- Fuel 115,256 17,291 94,186 Purchased power 185,301 131,638 48,937 Other operation and maintenance 62,241 33,890 21,726 Depreciation and amortization 39,012 20,693 15,028 Taxes other than income taxes 6,665 2,390 3,882 - -------------------------------------------------------------------- Total operating expenses 408,475 205,902 183,759 - -------------------------------------------------------------------- Operating income 273,305 177,110 85,708 Other income, net (2,029) 2,841 (5,450) Less -- Interest expense and other, net 31,273 22,675 8,249 Income taxes 85,221 56,764 25,946 Cumulative effect of accounting change 367 367 - - -------------------------------------------------------------------- Net Income $155,149 $100,879 $ 46,063 ====================================================================
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Power Company 2003 Annual Report
Revenues
Operating revenues in 2003 were $682 million, reflecting a $383 million increase from 2002. Operating revenues were positively impacted by a full year of energy and capacity sales through PPAs with Georgia Power and Savannah Electric that began in June 2002. New PPAs with Alabama Power and Georgia Power that commenced in June 2003 also contributed to the increase. Additionally, $80 million of contract termination revenues were recorded, as a result of the May 2003 termination of Dynegy's PPAs related to Plants Dahlberg and Franklin. See "Future Earnings Potential - Other Matters" and Note 3 to the financial statements under "Uncontracted Generating Capacity" for additional information. The remaining increases in operating revenues are a result of wholesale energy sales to non-affiliated companies under PPAs and through the Southern Company system power pool (Southern Pool). These sales were possible due to capacity made available from the commercial operation of Plant Franklin Unit 1 in June 2002, which was not fully obligated under a long-term PPA until June 2003 and test period energy sales transactions for Plant Franklin Unit 2 and Plant Harris Units 1 and 2 which were placed into commercial operation in June 2003. Capacity for Plant Harris Unit 2 is not obligated until June 2004. The Company also placed Plant Stanton A into commercial operation in October 2003. Other operating revenue increased by $9.9 million primarily due to transmission revenues, which were offset by additional transmission expense.
Operating revenues in 2002 were $298.8 million, reflecting a $269.5 million increase from 2001. In 2002, operating revenues were positively impacted by commercial operation of Plant Wansley Units 6 and 7 and Plant Franklin Unit 1 beginning in June 2002, and the initiation of PPAs with Georgia Power and Savannah Electric and requirements agreements with 11 EMCs in June 2002, as well as a full year of revenue from PPAs at Plant Dahlberg.
In 2001, operating revenues of $29.3 million were solely attributed to operations at Plant Dahlberg. The majority of the revenues, $26.4 million, were from capacity and energy sales to non-affiliated companies under PPAs. The remainder, $2.9 million, was from sales to affiliated companies through the Southern Pool.
Capacity revenues for 2003 were $201.6 million, or 33.4% of total revenues, excluding $80 million related to termination of contracts with Dynegy. Capacity revenues for 2002 were $123.9 million, or 41.5% of total revenues. Capacity revenues for 2001 were $18.6 million, or 63.5% of total revenues. These revenues are an integral component of the PPAs with both affiliate and non-affiliate customers.
Revenues from sales to affiliated companies through the Southern Pool that are not covered by PPAs will vary depending on demand and the availability and cost of generating resources at each company within the Southern Pool. These transactions do not have a significant impact on earnings since the energy is generally sold at cost.
Expenses
Natural gas fuel costs constitute a significant expense for the Company. The increase in fuel expense in 2003 is primarily due to the operation of Plant Wansley Units 6 and 7 and Plant Franklin Unit 1 for a full year, as well as new units at Plant Franklin and Plant Harris Units 1 and 2 which began operations in June 2003. In addition, the average cost of natural gas per decatherm increased 24% from 2002 to 2003. The increase in fuel expense in 2002 was primarily due to the commercial operation of Plant Wansley Units 6 and 7 and Plant Franklin Unit 1 beginning in June 2002, and a full year of operation for Plant Dahlberg. In addition, the average cost of natural gas per decatherm increased 33% from 2001 to 2002. The Company's PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel relating to energy delivered under such PPAs; therefore, these fuel cost increases do not have a significant impact on net income.
Purchased power from non-affiliates and affiliates increased by $27 million and $105 million, respectively, in 2003, and by $33.3 million and $15.6 million, respectively, in 2002, in all cases to meet the demands of the Company's contractual sales commitments.
Expenses from purchased power transactions will vary depending on demand and the availability and cost of generating resources accessible throughout the Southern Pool. Load requirements are submitted to the Southern Pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is Southern Power-owned generation, affiliate-owned generation or external purchases. During 2003, purchased power from affiliates increased as a result of the availability of lower cost generating capacity primarily due to the mild summer weather in Southern Company's retail service territory.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Power Company 2003 Annual Report
In 2003, other operation and maintenance expense increased by $33.9 million mainly due to increased administrative and general expenses of $12.7 million and other production expenses of $21.2 million. These increases are primarily attributed to a full year of operation at Plant Wansley Units 6 and 7 and Plant Franklin Unit 1, as well as the commercial operation of Plant Franklin Unit 2 and Plant Harris Units 1 and 2 beginning in June 2003.
In 2002, other operation and maintenance expense increased by $21.7 million mainly due to increased administrative and general expenses of $12.3 million and other production expenses of $9.4 million. These increases are primarily attributed to the June 2002 commercial operation of Plant Wansley Units 6 and 7 and Plant Franklin Unit 1.
Other operation expense in 2001 included administrative and general expenses of $5.6 million and other production expenses of $0.6 million related to the startup of the Company and the transfer of Plant Dahlberg in July 2001.
In 2003 and 2002, depreciation and amortization increased as a direct result of the commercial operation of Plant Wansley Units 6 and 7 and Plant Franklin Unit 1 in June 2002 and Plant Franklin Unit 2 and Plant Harris Units 1 and 2 in June 2003. The 2002 increase also reflects a full year of depreciation related to Plant Dahlberg, which was placed into service in July 2001.
In 2003 and 2002, the increases in taxes other than income taxes relate to property taxes for the commercial operation of Plant Wansley Units 6 and 7 and Plant Franklin Unit 1 in June 2002 and Plant Franklin Unit 2 and Plant Harris Units 1 and 2 in June 2003. The 2002 increase also reflects a full year of Plant Dahlberg's property taxes.
Interest expense in 2003 increased by $22.7 million from the amount recorded in 2002. This increase is primarily attributed to a lower percentage of interest costs being capitalized as projects have reached completion and an increase in the amount of long-term debt outstanding. Interest expense in 2002 increased by $8.2 million from the amount recorded in 2001. This increase in 2002 is primarily attributed to increased debt associated with the Company's ongoing construction program.
Changes in other income, net in 2003 and 2002 resulted primarily from 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."
Effects of Inflation
The Company is subject to long-term contracts and income tax laws that are based on the recovery of 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 generating facilities 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.
Future Earnings Potential
General
The results of operations for the past three years are not necessarily indicative of future earnings potential. Several factors affect the opportunities, challenges, and risks of the Company's competitive wholesale energy business. These factors include the ability to achieve energy 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 completion of construction on new generating facilities, regulatory matters, including those related to affiliate contracts, energy sales, creditworthiness of customers, total generating capacity available in the Southeast, and the successful remarketing of capacity as current contracts expire.
The Company is working to maintain and expand its share of wholesale energy sales in the Southeastern power markets. By the end of 2005, the Company plans to have approximately 6,000 megawatts of available generating capacity in commercial operation. At December 31, 2003, 4,775 megawatts were in commercial operation.
Although under some of the Company's PPAs energy will be sold to Southern Company's five retail operating companies, the Company's generating facilities will not be in the retail operating companies' regulated rate bases, and the
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Company will not be able to seek recovery from the affiliated companies' ratepayers for construction, repair, environmental or maintenance costs. It is expected that the capacity payments in the PPAs will produce sufficient cash flow to meet these 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 most 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 purchasers are responsible for procuring and transporting the fuel to the particular generating facility.
The Company's PPAs with non-affiliated counterparties have provisions that require the posting of collateral or an acceptable substitute guarantee in the event that (a) Standard & Poor's or Moody's downgrades the credit ratings of such counterparty to below investment grade, or, (b) 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.
Fixed and variable operation and maintenance (O&M) costs will be covered either through capacity charges or other charges based on dollars per kilowatt year or dollars per megawatt hour. The Company has also entered into long-term service contracts with General Electric (GE) to reduce its exposure to certain O&M costs relating to GE equipment.
FERC Matters
Market-Based Rate Authority
The Company currently has general authorization from the Federal Energy Regulatory Commission (FERC) to sell power to nonaffiliates at market-based prices. In addition, each of the retail operating companies has obtained FERC approval to sell power to nonaffiliates at market-based prices under specific contracts. Southern Power and the retail operating companies also have FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities' applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company's retail operating companies, and found them to be "pivotal suppliers" in their service areas and ordered the implementation of several mitigation measures. SCS, on behalf of the retail operating companies and others sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. SCS, on behalf of the retail operating companies and others submitted comments to the FERC in 2002 regarding these issues. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. Southern Company anticipates that the FERC will address the requests for rehearing in the near future. Regardless of the outcome of the SMA proposal, the FERC retains the ability to modify or withdraw the authorization for any seller to sell at market-based rates, if it determines that the underlying conditions for having such authority are no longer applicable. In that event, the Company would be required to obtain FERC approval of rates based on cost of service, which may be lower than those in negotiated market-based rates. The final outcome of this matter will depend on the form in which the SMA test and mitigation measures rules may be ultimately adopted and cannot be determined at this time.
PPAs by Georgia Power and Savannah Electric for the Company's Plant McIntosh capacity were certified by the Georgia Public Service Commission (GPSC) in December 2002 after a competitive bidding process. In April 2003, the Company applied for FERC approval of these PPAs. Interveners opposed the FERC's acceptance of the PPAs, alleging that the PPAs do not meet the applicable standards for market-based rates between affiliates. In July 2003, the FERC accepted the PPAs to become effective as scheduled on June 1, 2005, subject to refund, and ordered that hearings be held to determine: (a) whether, in the design and implementation of the GPSC competitive bidding process, Georgia Power and Savannah Electric unduly preferred the Company; (b) whether the analysis of the competitive bids unduly favored the Company, particularly with respect to evaluation of non-price factors; (c) whether Georgia Power and Savannah Electric selected their affiliate, the Company, based upon a reasonable combination of price and non-price factors; (d) whether the Company received an undue preference or competitive advantage in the competitive bidding process as a result of access to its affiliate's transmission system; (e) whether and to what extent the PPAs impact wholesale competition; and (f) whether the PPAs are just and reasonable and not unduly discriminatory. Hearings are scheduled to begin in
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March 2004. Management believes that the PPAs should be approved by the FERC; however, the ultimate outcome of this matter cannot now be determined.
Industry Restructuring
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 Policy Act of 1992 (Energy Act). The Energy Act allowed independent power producers to access a utility's transmission network in order to sell electricity to other utilities.
Since 2001, merchant energy companies and traditional electric utilities with significant energy marketing and trading activities have come under severe financial pressures. Many of these companies have completely exited or drastically reduced all energy marketing and trading activities and sold foreign and domestic electric infrastructure assets. The Company has not experienced any material adverse financial impact regarding its limited energy trading operations and recent generating capacity additions. In general, the Company only constructs new generating capacity after entering into long-term capacity contracts for the new facilities, which is optimized by limited energy trading activities.
Power Sales Agreements
In June 2003, the Company placed Plant Franklin Unit 2 and Plant Harris Units 1 and 2 into commercial operation. In October 2003, the Company placed Plant Stanton A into commercial operation. In June 2004, the Company's PPA with Georgia Power will begin for Plant Harris Unit 2. PPAs for the other units became effective upon commercial operation. The Company also has Plant McIntosh Units 10 and 11 under construction. Most of the Company's generating capacity in operation, under construction, or planned has been sold under PPAs.
In June 2002, PPAs with Georgia Power and Savannah Electric and requirements agreements with 11 EMCs went into effect upon the commercial operation of Plant Wansley Units 6 and 7 and Plant Franklin Unit 1.
Also, effective in January 2003, the Company entered into contracts with North Carolina Municipal Power Authority 1 (NCMPA) and the City of Dalton (Dalton). Under the NCMPA contract, the Company is responsible for supplying NCMPA's capacity and energy needs in excess of its existing resources and disposing of its surplus energy through December 31, 2004. Under the Dalton contract, the Company is responsible for supplying Dalton's requirements for capacity and energy in excess of Dalton's existing resources for the next 15 years, with a customer option to convert to a fixed capacity purchase at the end of year 10.
In July 2003, the Company entered into a requirements service agreement with Piedmont Municipal Power Agency (PMPA). PMPA is a full requirements provider to 10 South Carolina cities. Under this agreement, the Company will be responsible for supplying PMPA's capacity and energy needs in excess of PMPA's existing resources and will purchase PMPA's surplus energy. The initial contract term is for 5 years beginning in 2006 with mutual renewal options through 2015.
The Company has entered into long-term power sales agreements for portions of its generating unit capacity as follows:
Project Capacity Contract (megawatts)* Term --------------------------------------------------------- Affiliated ---------- Franklin Unit 1 571 ** 6/02-5/10 Franklin Unit 2 615 *** 6/03-5/11 Wansley Units 6 & 7 1,134 6/02-12/09 Harris Unit 1 618 6/03-5/10 Harris Unit 2 618 **** 6/04-5/19 McIntosh 1,240 6/05-5/20 --------------------------------------------------------- Total Affiliated 4,796 ---------------------------------------------------------
Non-Affiliated -------------- Dahlberg Units 1-7 578 6/00-12/04 Stanton A 396 11/03-11/13 --------------------------------------------------------- Total Non-affiliated 974 --------------------------------------------------------- * According to the original contract terms ** 370 megawatts during the first year *** 400 megawatts during the first year **** Contract does not begin until second year of operation of Plant Harris Unit 2.
Capacity revenues from these long-term power sales agreements amounted to $201.6 million, $123.9 million, and $18.6 million for the periods ended December 31, 2003, 2002, and 2001, respectively. Forecasted future capacity revenues under existing PPAs are expected to total $3.3 billion for affiliated contracts and $1.1 billion for non-affiliated contracts. These capacity revenues will
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continue to represent approximately 40% of total annual revenues through 2007. At that point, as certain existing contracts reach termination, assuming no new contracts, capacity revenues are expected to decline to approximately 25% of total annual revenues. Consistent with the Company's strategy to sell energy under long-term contracts, capacity payments will continue to be an integral ` part of future contract negotiations. As such, capacity revenues will continue to be a significant portion of annual revenues.
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. Compliance with these environmental requirements may involve significant costs. Such 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 also increase the cost of siting and operating any type of future electric generating facility.
Federal and state environmental regulatory agencies are actively considering and developing additional control strategies for emission of air pollution from industrial sources, including electric generating facilities. Among the various air quality matters being planned or considered for regulation by the federal Environmental Protection Agency and/or relevant state agencies are: designation of new target areas as non-attainment for ozone and particulate matter under applicable federal air quality standards; the reduction of nitrogen oxide and particulate matter emissions to reduce regional haze and visibility impairment in sensitive areas; proposed reductions in sulfur dioxide and nitrogen oxide emissions to reduce interstate transport of such pollutants; regulations addressing the construction or modification of sources of regulated pollutants; the development of appropriate control standards and technologies for emissions of mercury; and the reduction of so-called "greenhouse gases" (such as carbon dioxide) to address concerns over global climate change. Development and implementation of final federal and state rules on these issues could require further substantial reductions in all air emissions associated with electricity generation.
Federal and state environmental regulatory agencies are also reviewing and evaluating various other matters, including hazardous waste disposal requirements, requirements for cooling water intake structures and establishment of total pollutant loads for certain impaired waters. The impact of any new standards or requirements will depend on the development and implementation of applicable regulations.
Several major pieces of environmental legislation are periodically considered for reauthorization or amendment by Congress. These 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. In 2003, several major bills to amend the Clean Air Act to impose more stringent emissions limitations were proposed to further limit power plant emissions of sulfur dioxide, nitrogen oxides, mercury, and, in some cases, carbon dioxide. The cost impacts of such legislation would depend upon the specific requirements enacted and cannot be determined at this time.
Compliance with possible additional federal or state legislation or regulations related to global climate change or other environmental and health concerns could also significantly affect the Company. The impact of any new legislation, changes to existing legislation, or environmental regulations could affect many areas of the Company's operations. While all of the Company's PPAs generally contain provisions that permit charging the purchaser 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.
Litigation over environmental issues and claims of various types, including property damage, personal injury and citizen enforcement of environmental requirements, 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 litigation against the Company cannot be predicted at this time; however, 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.
Other Matters
On May 21, 2003, the Company entered into an agreement with Dynegy that resolved and terminated in 2003 all outstanding matters related to capacity sales contracts with subsidiaries of Dynegy. The termination payments from Dynegy resulted in a one-time gain to the Company of approximately $50 million. As a result of the Dynegy capacity contract terminations, the Company is completing
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limited construction activities on Plant Franklin Unit 3 to preserve the long-term viability of the project but has deferred final completion until the 2008-2011 period. The length of the deferral period will depend on forecasted capacity needs and other wholesale market opportunities. The Company is continuing to explore alternatives for its existing uncontracted capacity. See Note 3 to the financial statements under "Uncontracted Generating Capacity" for additional information.
The Company is involved in various matters being litigated and regulatory matters that could affect future earnings. 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 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.
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. 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: o Assessing whether a sales contract meets the definition of a lease o Assessing whether a sales contract meets the definition of a derivative o Assessing whether a sales contract meets the definition of a capacity contract o Assessing the probability at inception and throughout the term of the individual contract that the contract will result in physical delivery o Ensuring that the contract quantities do not exceed available generating capacity o Identifying the hedging instrument, the hedged transaction, and the nature of the risk being hedged o Assessing hedge effectiveness at inception and throughout the contract term.
Normal Sale and Non-Derivative Transactions - ------------------------------------------- The Company considers derivative contracts, including capacity contracts, that provide for the sale of electricity to be physically delivered in quantities less than the Company's available generating capacity to be normal sales. In accordance with Statement No. 133, such transactions are accounted for as executory contracts and are not subject to mark to market accounting. Therefore, 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 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, 2003.
Cash Flow Hedge Transactions - ---------------------------- The Company has designated other derivative contracts for sales 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. At December 31, 2003, approximately $1 million in unrealized gains (losses) were deferred in Other Comprehensive Income.
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
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through net income. Net unrealized losses on such contracts totaled approximately $1.9 million for the year ended December 31, 2003.
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: o Future demand for electricity based on projections of economic growth and estimates of available generating capacity o Future power and natural gas prices, which have been quite volatile in recent years o Future operating costs. To date, the Company's evaluations of its assets have not required any impairment to be recorded. See Note 3 to the financial statements under "Uncontracted Generating Capacity" for additional information.
New Accounting Standards
Prior to January 2003, the Company accrued for the ultimate cost of retiring most long-lived assets over the life of the related asset through depreciation expense. FASB Statement No. 143, Accounting for Asset Retirement Obligations established new accounting and reporting standards for legal obligations associated with the ultimate cost of retiring long-lived assets. 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. Additionally, non-regulated companies are no longer permitted to continue accruing future retirement costs for long-lived assets that they do not have a legal obligation to retire.
The Company has no liability for asset retirement obligations. In January 2003, the Company recorded a reduction to the accumulated reserve for depreciation and a cumulative effect of change in accounting principle of $0.6 million ($0.4 million after-tax). This represents removal costs accrued prior to the implementation of Statement No. 143.
FASB Statement No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, which further amends and clarifies the accounting and reporting for derivative instruments, became effective generally for financial instruments entered into or modified after June 30, 2003. Current interpretations of Statement No. 149 indicate that certain electricity forward transactions subject to unplanned netting -- including those typically referred to as "book outs" -- may only qualify as cash flow hedges if an entity can demonstrate that physical delivery or receipt of power occurred. The Company's forward electricity contracts continue to be exempt from fair value accounting requirements or to qualify as cash flow hedges, with the related gains and losses deferred in other comprehensive income. The implementation of Statement No. 149 did not have a material effect on the Company's financial statements.
In July 2003, the EITF of FASB issued EITF No. 03-11, which became effective on October 1, 2003. The standard addresses the reporting of realized gains and losses on derivative instruments and is being interpreted to require book outs to be recorded on a net basis in operating revenues. Adoption of this standard did not have a material impact on the Company's financial statements.
FINANCIAL CONDITION AND LIQUIDITY - ---------------------------------
Overview
The major change in the Company's financial condition during 2003 was the addition of approximately $344.4 million to utility plant related to on-going construction of combined-cycle units. The funds for these additions were provided by the Company's credit facility, the issuance of senior notes in July 2003, commercial paper, capital contributions and subordinated loans from Southern Company, and internally generated cash from operations. The Statements of Cash Flows provide additional information.
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Sources of Capital
The Company will use external funds, equity capital from Southern Company and internally generated cash from operations to finance its construction program. External funds will be from the issuance of unsecured senior debt and commercial paper or utilization of existing credit arrangements from banks.
Currently, Southern Company provides limited credit support to the Company. 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. In accordance with the Public Utility Holding Company Act, most loans between affiliated companies must be approved in advance by the Securities and Exchange Commission (SEC).
The Company's current liabilities frequently exceed current assets because of the continued use of short-term debt as an interim funding source for the Company's ongoing construction program and the seasonality of the electricity business.
At December 31, 2003, the Company had approximately $2.8 million of cash and cash equivalents to meet short-term cash needs and contingencies. To meet liquidity and capital resource requirements, the Company had at December 31, 2003, $650 million of unused committed credit arrangements with banks as shown in the following table.
At the beginning of 2004, bank arrangements are as follows:
Expires -------------------------------- Total Unused 2004 2005 & beyond - ------------------------------------------------------------- (in millions) $650 $650 $-- $650 - -------------------------------------------------------------
The $650 million of unused credit arrangements is committed to provide liquidity support to the Company's commercial paper program. The commercial paper program is used to finance acquisition and construction costs related to gas-fired electric generating facilities and for general corporate purposes, subject to borrowing limitations for each generating facility. The credit arrangements permit the Company to fund construction of future generating facilities upon meeting certain requirements. At December 31, 2003, the Company had $114.3 million in outstanding commercial paper. See Note 6 to the financial statements for additional information.
Financing Activities
During 2003, the Company repaid subordinated loans from Southern Company of approximately $20 million, net of additional borrowings. In March 2003, $190 million of notes payable to Southern Company were converted to a capital contribution from Southern Company. In September 2003, the SEC approved the Company's payment of dividends in an amount up to $190 million to Southern Company from capital surplus. The first such dividend of $77 million, recorded as a reduction of paid-in capital, was made in October 2003. Equity contributions and subordinated loans from Southern Company totaled $850 million at the end of 2003.
In July 2003, the Company issued $575 million of senior notes. The proceeds from the sale were used to repay a substantial portion of existing short-term indebtedness, to settle interest rate hedges associated with such senior notes and for general corporate purposes. See Note 6 to the financial statements under "Long-Term Debt" and "Financial Instruments" for further information. The interest rate swap agreements that the Company entered into in anticipation of this issuance were settled at a $93.3 million loss. This amount has been deferred in other comprehensive income and will be amortized to interest expense over the life of the senior notes.
Credit Rating Risk
The Company does not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are contracts that could require collateral -- but not accelerated payment -- in the event of a credit rating change to below investment grade. These contracts are primarily for physical electricity purchases and sales, fixed-price physical gas purchases and agreements covering interest rate swaps. At December 31, 2003, the maximum potential collateral requirements under the electricity sales contracts were approximately $161 million. Generally, collateral may be provided for by a Southern Company guaranty, a letter of credit, or cash. At December 31, 2003, there were no material collateral requirements for the gas purchase contracts.
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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 purchasers, the Company's exposure to market volatility in commodity fuel prices and prices of electricity is limited. To mitigate residual risks in those areas, the Company enters into fixed-price contracts for the sale of electricity. In connection with the transfers of Plant Franklin in 2001 and Plant Wansley in 2002 to the Company, Georgia Power transferred approximately $5.6 million and $1.6 million, respectively, in derivative assets relating to electric and gas forward contracts in effect at the applicable date of the transfers. These contracts were recorded at fair value on the applicable date of the transfer, which was equal to Georgia Power's carrying amount. Following the transfer, these contracts were marked to market through income until realized and settled in August 2003.
In prior years, to reduce its exposure to fluctuations in the exchange rate for Euros, the Company entered into forward Euro purchase contracts designated as fair value hedges of certain firm equipment purchase commitments that required payment in Euros. As of May 2003, all Euro payments have been made and the resulting gains associated with the hedges effectively reduced the purchase price of the equipment, which is included in plant-in-service or construction work in progress.
The fair value of changes in derivative energy contracts and year-end valuations were as follows at December 31:
Changes in Fair Value ----------------------------------------------------------- 2003 2002 ----------------------------------------------------------- (in thousands) Contracts beginning of year $3,864 $ 5,496 Contracts realized or settled (4,416) (4,336) New contracts at inception - 1,576 Current period changes 1,217 1,128 ----------------------------------------------------------- Contracts end of year $ 665 $ 3,864 ===========================================================
At December 31, 2003, all of these contracts are actively quoted and mature within one year.
Unrealized pre-tax gains and losses on electric 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 income statement as incurred. At December 31, 2003, the fair value of derivative energy contracts was as follows:
Amounts - ------------------------------------------------------------------- (in thousands) Other comprehensive income $ 950 Net income (285) - ------------------------------------------------------------------- Total fair value $ 665 ===================================================================
Approximately $(1.9) million, $(4.9) million and $0.6 million of unrealized pre-tax gains (losses) were recognized in income in 2003, 2002, and 2001, respectively. 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."
At December 31, 2003, 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
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interest rates. The Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term. See "Financing Activities" herein and Notes 1 and 6 to the financial statements under the heading "Financial Instruments" for additional information.
Capital Requirements and Contractual Obligations
The construction program of the Company is currently estimated to be $259 million for 2004, $254 million for 2005, and $355 million for 2006. Actual construction costs may vary from these estimates because of changes in factors such as: business conditions; environmental regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. The Company has approximately 1,240 megawatts of new generating capacity scheduled to be placed in service by 2005.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, 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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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 five retail operating companies, Southern Company Services (SCS), Southern Communication Services (Southern LINC), Southern Company Gas (Southern Company GAS), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The retail operating companies -- Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company -- provide electric service in four Southeastern states. The Company constructs, owns and manages Southern Company's competitive generation assets and sells electricity at market-based rates in the wholesale market. Contracts among the retail operating companies and the Company -- related to jointly owned generating facilities, interconnecting transmission lines or the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission (SEC). SCS, the system service company, provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern Company GAS is a competitive retail natural gas marketer serving customers in Georgia. Southern Holdings is an intermediate holding subsidiary for Southern Company's investments in synthetic fuels and leveraged leases and an energy services business. Southern Nuclear operates and provides services to Southern Company's nuclear power plants.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. In addition, the retail operating companies and the Company are subject to regulation by the 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 Company was formed on January 8, 2001 and began commercial operations in August 2001 after Georgia Power transferred its interest in Plant Dahlberg Units 1 through 10. See Note 2 for further information regarding asset transfers from affiliates. The financial statements include the accounts of the Company and its wholly-owned subsidiary, Southern Company - Florida LLC (SCF) which was established to own, operate and maintain Plant Stanton Unit A. See Note 4 for further information. All intercompany accounts and transactions have been eliminated in consolidation.
Certain prior years' data presented in the financial statements have been reclassified to conform with current year presentation.
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. 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 cost under agreements with SCS or the retail operating companies. Costs for these services from SCS amounted to approximately $47.7 million in 2003, $29.5 million in 2002, and $12 million during 2001. Approximately $32.8 million in 2003, $16.2 million in 2002, and $4.7 million in 2001 were general, administrative, operation and maintenance expenses; the remainder was capitalized to construction work in progress. Cost allocation methodologies used by SCS are approved by the SEC and management believes they are reasonable.
The Company has agreements with Georgia Power and Alabama Power to provide operation and maintenance services for Plants Dahlberg, Wansley, Franklin, and Harris. These services are billed at cost on a monthly basis and are recorded as
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operations and maintenance expense in the accompanying statements of income. For the periods ended December 31, 2003, 2002, and 2001, these services totaled approximately $6.3 million, $5.3 million, and $1.0 million, respectively.
Additionally, the Company has agreements with Alabama Power and Georgia Power to provide procurement, payables and other functions related to the construction at Plants Harris and Franklin in Alabama and Plant Wansley in Georgia. Costs for these services are billed monthly and are capitalized.
Effective June 2003, the Company entered into Power Purchase Agreements (PPAs) with Alabama Power and Georgia Power for the sale of capacity and energy from Plants Harris and Franklin. Billings under these agreements totaled $67.2 million, including $13.4 million of affiliated deferred capacity revenues included in deferred capacity revenues on the Balance Sheets at December 31, 2003.
Effective June 2002, the Company entered into PPAs with Georgia Power and Savannah Electric for the sale of capacity and energy from Plants Wansley and Franklin. For 2003, billings under these agreements totaled $215 million, including $15 million of affiliated deferred capacity revenues. For 2002, billings under these agreements totaled $164 million, including $13 million of affiliated deferred capacity revenues. These deferred capacity revenues are included on the Balance Sheets at December 31, 2003 and 2002, respectively.
The retail operating companies, Southern Power, and Southern Company GAS 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 its affiliates 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.
Also see Notes 3 and 6 for information related to various types of financing support provided by Southern Company.
Revenues and Fuel Costs
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. See "Financial Instruments" herein for additional information.
Significant portions of the Company's revenues have been derived from certain customers. For the year ended December 31, 2003, Georgia Power accounted for approximately 33.7% of revenues, excluding $80 million related to termination of contracts with Dynegy, Inc. (Dynegy). For the year ended December 31, 2002, Georgia Power, Savannah Electric, and LG&E Energy Marketing, Inc. accounted for approximately 33.5%, 17.2% and 15.8% of revenues, respectively. For the period ended December 31, 2001, LG&E Energy Marketing, Inc. and Dynegy Power Marketing Inc. accounted for approximately 66% and 21% of revenues, respectively.
Fuel costs are expensed as the fuel is consumed. The Company relies mainly on natural gas to fuel its generating units. See Note 7 herein under "Fuel Commitments" for further details on future commitments.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences.
Manufacturer's Tax Credits
The State of Georgia provides a tax credit for qualified investment property to manufacturing companies that construct new facilities. The credit ranges from 1% to 5% of construction expenditures depending upon the county in which the new facility is located. The Company's policy is to recognize these credits when management believes they are more likely than not to be allowed by the Georgia Department of Revenue.
Depreciation
Depreciation of the original cost of assets is computed under the straight-line method based on the assets' estimated useful lives determined by the Company.
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The primary assets in property, plant and equipment are power plants all of which have an estimated useful life of 35 years, except Plant Dahlberg which has an estimated useful life of 40 years.
Asset Retirement Obligations And Other Costs of Removal
Prior to January 2003, the Company followed the industry practice of accruing for the ultimate costs of retiring most long-lived assets over the life of the related asset as part of the annual depreciation expense provision. Effective January 1, 2003, the Company adopted Financial Accounting Standards Board (FASB) Statement No. 143, Accounting for Asset Retirement Obligations. Statement No. 143 establishes new accounting and reporting standards for legal obligations associated with the ultimate costs of retiring long-lived assets. The present value of the ultimate costs for an asset's future retirement must be recorded in the period in which the liability is incurred. The costs must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Additionally, Statement No. 143 does not permit the continued accrual of future retirement costs for long-lived assets that the company does not have a legal obligation to retire.
The Company has no liability for asset retirement obligations. In January 2003, the Company recorded a reduction to the accumulated reserve for depreciation and a cumulative effect of change in accounting principle of $0.6 million ($0.4 million after-tax). This represents removal costs accrued prior to the implementation of Statement No. 143.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost. Original cost includes materials, direct labor incurred by affiliated companies, minor items of property, and interest capitalized. Interest is capitalized on qualifying projects during the development and construction period. Interest of approximately $36.7 million in 2003, $35.3 million in 2002, and $2.9 million in 2001, was capitalized in connection with the development and construction of power plants. The cost of maintenance, repairs and replacement of minor items of property is charged to maintenance expense as incurred. The cost of replacements of property that extend the useful life of the plant, exclusive of minor items of property, is capitalized.
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 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 loss recognized is determined by estimating the fair value of the assets and recording a loss for the amount of the carrying value that 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 $2.2 million at December 31, 2003 and $3.6 million at December 31, 2002.
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 transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. Materials and supplies are recorded at average cost.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases and
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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, 2003 were as follows:
Carrying Fair Amount Value ------------------------ Long-term debt: (in millions) At December 31, 2003 $1,149 $1,172 At December 31, 2002 $956 $990 - --------------------------------------------------------------
The fair values for securities 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. ASSET TRANSFERS
On July 31, 2001, Georgia Power transferred its interests in Plant Dahlberg Units 1 through 10 and related working capital to the Company. In accordance with the affiliate transaction rules of PUHCA, these assets were transferred at Georgia Power's net carrying costs of $260.1 million. The transferred assets consist primarily of 10 combustion turbine units (810 MW) in operation, all located in Jackson County, Georgia. In connection with the asset transfer, Georgia Power also assigned to the Company its interest in three PPAs related to Plant Dahlberg. The results of operations of Plant Dahlberg were included in the financial statements from August 1, 2001.
The following projects, which were under construction, were transferred from Alabama Power and Georgia Power to the Company and recorded in construction work in progress at the respective affiliate's book value:
Transferred Amount Plant From Date (in millions) - ------------------------------------------------------------------- Harris Alabama Power 06/2001 $ 91.4 Units 1 & 2 Franklin Alabama Power 11/2001 $267.9 Units 1 & 2 and Georgia Power Wansley Georgia Power 01/2002 $389.9 Units 6 & 7 - -------------------------------------------------------------------
In conjunction with these transfers, Alabama Power and Georgia Power assigned PPAs to the Company related to these plants. Georgia Power required that certain counterparties to the Dahlberg PPAs make prepayments for operational rights to the units. These prepayments were recorded as liabilities by Georgia Power and were transferred to the Company in connection with the Plant Dahlberg transfer. At December 31, 2003, and 2002, the unamortized balance of these amounts totaled $1.4 million and $2.8 million, respectively, and is being amortized into income over the life of the agreements.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury and citizen enforcement of environmental requirements, has increased generally throughout the United
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States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such litigation against the Company cannot be predicted at this time; however, 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.
Uncontracted Generating Capacity
In May 2003, the Company entered into an agreement with Dynegy to resolve all outstanding matters related to capacity sales contracts with subsidiaries of Dynegy. Under the terms of the agreement, Dynegy made a cash termination payment of $80 million to the Company. The termination payments from Dynegy resulted in a one-time gain to the Company of approximately $50 million.
As a result of the contract termination, the Company is completing limited construction activities on Plant Franklin Unit 3 to preserve the long-term viability of the project but has deferred final completion until the 2008-2011 period. The length of the deferral period will depend on forecasted capacity needs and other wholesale market opportunities. As of December 31, 2003, the Company's investment in Unit 3 of Plant Franklin was $156 million. The Company is also continuing to explore alternatives for its existing uncontracted capacity. The final outcome of these matters cannot now be determined.
FERC Matters
Market-Based Rate Authority
The Company currently has general authorization from the FERC to sell power to nonaffiliates at market-based prices. In addition, each of the retail operating companies has obtained FERC approval to sell power to nonaffiliates at market-based prices under specific contracts. Southern Power and the retail operating companies also have FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities' applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company, and found Southern Company and others to be "pivotal suppliers" in their service areas and ordered the implementation of several mitigation measures. SCS, on behalf of the retail operating companies and others sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. SCS, on behalf of the retail operating companies and others submitted comments to the FERC in 2002 regarding these issues. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. Southern Company anticipates that the FERC will address the requests for rehearing in the near future. The final outcome of this matter will depend on the form in which the SMA test and mitigation measures rules may be ultimately adopted and cannot be determined at this time.
PPAs by Georgia Power and Savannah Electric for the Company's Plant McIntosh capacity were certified by the Georgia Public Service Commission (GPSC) in December 2002 after a competitive bidding process. In April 2003, the Company applied for FERC approval of these PPAs. Interveners opposed the FERC's acceptance of the PPAs, alleging that the PPAs do not meet the applicable standards for market-based rates between affiliates. In July 2003, the FERC accepted the PPAs to become effective as scheduled on June 1, 2005, subject to refund, and ordered that hearings be held to determine: (a) whether, in the design and implementation of the GPSC competitive bidding process, Georgia Power and Savannah Electric unduly preferred the Company; (b) whether the analysis of the competitive bids unduly favored the Company, particularly with respect to evaluation of non-price factors; (c) whether Georgia Power and Savannah Electric selected their affiliate, the Company, based upon a reasonable combination of price and non-price factors; (d) whether the Company received an undue preference or competitive advantage in the competitive bidding process as a result of access to its affiliate's transmission system; (e) whether and to what extent the PPAs impact wholesale competition; and (f) whether the PPAs are just and reasonable and not unduly discriminatory. Hearings are scheduled to begin in March 2004. Management believes that the PPAs should be approved by the FERC; however, the ultimate outcome of this matter cannot now be determined.
4. JOINT OWNERSHIP AGREEMENTS
Southern Power, through its wholly owned subsidiary SCF, is a 65% owner of Plant Stanton Unit A (Stanton A), a combined-cycle project with 660 megawatts. The unit is co-owned by Orlando Utilities Commission (28%), Florida Municipal Power Agency (3.5%), and Kissimmee Utility Authority (3.5%). The Company has a services agreement with SCS where SCS is responsible for the operation and maintenance of Stanton A and was responsible for the overall construction project management. Construction on Stanton A began in October 2001 and the unit
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was placed in service on October 1, 2003. As of December 31, 2003 $155.3 million is recorded in plant in service with associated accumulated depreciation of $1.1 million. The Company's proportionate share of the plant's operating expense is included in the corresponding operating expenses in the Statements of Income. At December 31, 2002, the Company's share of the construction costs for Stanton A was $128.3 million, and was recorded in construction work in progress in the Balance Sheets.
The Company has guaranteed the performance of its subsidiary, SCF, for SCF's payment obligations under the ownership agreement, PPAs and alternative power supply agreements associated with the Stanton A project. The Company's current exposure is $32.5 million under the PPAs and the ownership agreement and $3.4 million under alternative power supply agreements.
5. INCOME TAXES
Southern Company and its subsidiaries file a consolidated federal income tax return. In 2002, Southern Company began filing a combined State of Georgia income tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. In accordance with Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability.
Details of the income tax provisions are as follows:
2003 2002 2001 - --------------------------------------------------------------- (in thousands) Total provision for income taxes: Federal: Current $64,090 $26,900 $1,402 Deferred 19,354 2,338 3,017 -------------------------------------------------------------- 83,444 29,238 4,419 - --------------------------------------------------------------- State: Current 10,459 4,622 240 Deferred 3,318 401 517 State manufacturer's Tax credits (11,769) (5,804) (2,665) - --------------------------------------------------------------- 2,008 (781) (1,908) - ---------------------------------------------------- ---------- Total $85,452 $28,457 $2,511 ===============================================================
The Company recorded a reduction in 2003, 2002, and 2001 tax expense of approximately $11.8 million, $5.8 million, and $2.7 million, respectively, under the flow-through method of accounting for the State of Georgia manufacturer's tax credits.
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:
2003 2002 - --------------------------------------------------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $(44,602) $(17,401) Other - (729) - --------------------------------------------------------------- Total (44,602) (18,130) - --------------------------------------------------------------- Deferred tax assets: Book/tax basis difference on asset transfer 15,061 15,644 Levelized capacity revenues 11,052 8,003 Other comprehensive loss on interest rate swaps 40,003 30,745 Other 397 2,329 - --------------------------------------------------------------- Total 66,513 56,721 - --------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $21,911 $38,591 ===============================================================
Deferred tax liabilities were primarily the result of property related timing differences and derivative hedging instruments. Deferred tax assets were primarily the result of a deferred tax gain related to the transfer of Plant Dahlberg from Georgia Power. The Company has recognized a payable to Georgia Power for Georgia Power's deferred tax liability resulting from this gain of approximately $15.1 million at December 31, 2003 and $15.6 million at December 31, 2002, which is recorded in other affiliated deferred credits on the Balance Sheets.
A reconciliation of the federal statutory tax rate to the effective income tax rate is as follows:
2003 2002 2001 - -------------------------------------------------------------- Federal statutory rate 35.0 35.0 35.0 State income tax, net of federal deduction 3.7 3.9 4.6 State manufacturer's tax credits, net of federal effect (3.2) (4.5) (16.2) - -------------------------------------------------------------- Effective income tax rate 35.5 34.4 23.4 ==============================================================
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6. CAPITALIZATION
Parent Company Transactions
Southern Company is currently authorized by the SEC under the PUHCA to fund the development of Southern Power up to an aggregate amount not to exceed $1.7 billion, which may take the form of purchases or contributions of equity interests, loans and guarantees issued in support of the Company's securities or obligations. At December 31, 2003, equity contributions and subordinated loans from Southern Company totaled $850 million.
Southern Company has committed to fund at least 35% of the Company's construction project financing and to pay for construction cost overruns to the extent that the Company's own cash flow is insufficient. Also, Southern Company will prepay any portion of revolving credit arrangements used for the Company's construction projects not completed within two years of the proposed completion date. Currently, there are no borrowings related to the construction of Plant Franklin Unit 3 outstanding under these credit arrangements.
In 2001, Southern Power entered into an intercompany note payable to Southern Company, which was payable on demand. At December 31, 2002, $210.5 million was outstanding with an interest rate of 5.04%. In March 2003, $190 million of notes payable to Southern Company were converted to a capital contribution from Southern Company. At December 31, 2003, there were no amounts outstanding under this agreement.
Bank Credit Arrangements
In 2003, the Company amended and restated its $850 million unsecured syndicated revolving credit facility (Facility) expiring in April 2006, reducing the Facility to $650 million. The purpose of the Facility is to finance the acquisition and construction costs related to gas-fired electric generating facilities and general corporate expenditures (subject to a $50 million limit), and to pay or support commercial paper used to fund construction of facilities. At December 31, 2003, the Company had no outstanding borrowings under the Facility. Borrowings under the Facility bear interest at the Company's option equal to either the Eurodollar rate plus a specified margin ranging from 1.25% to 3.0%, depending on the Company's credit rating and the amount drawn down under the Facility, or a base rate plus a specified margin. The interest rate and average interest rate on the Facility were 2.73% and 3.15% at December 31, 2002, and 3.44% and 3.61% at December 31, 2001, and during the periods then ended. The Company is required to pay a commitment fee on the unused balance of the Facility. The commitment fee ranges from 0.325% to 0.75%, depending on the Company's credit rating. For the periods ended December 31, 2003, 2002 and 2001, the Company paid approximately $2.0 million, $1.1 million, and $0.1 million in commitment fees, respectively.
The Facility contains certain financial covenants relating to the Company's debt capitalization which require that additional debt incurred by the Company must generally be unsecured and the Company must have its ratings reaffirmed at investment grade including the new debt. The Facility also contains restrictions related to the assumption of additional debt, which require a maximum 65% debt ratio, as defined in the Facility, excluding intercompany loans. The Company was in compliance with such covenants at December 31, 2003. Initial borrowings under the Facility for new projects would be prohibited if the Company or Southern Company experiences a material adverse change (as defined in the Facility). The Facility contains a cross default to Southern Company's indebtedness, which if triggered would require prepayment of debt related to projects financed under the Facility that are not complete.
Long-Term Debt
In July 2003, the Company issued $575 million of 4.875% senior notes, due July 15, 2015. In June 2002, the Company issued $575 million of 6.25% senior notes, due July 15, 2012.
Commercial Paper
In February 2003, the Company initiated a commercial paper program to fund a portion of the construction costs of new plants. The Company's strategy is to refinance such short-term borrowings with long-term securities following plant completion. During 2003, the peak amount outstanding for commercial paper was $493 million and the average amount outstanding was $239 million. The average annual interest rate on commercial paper was 1.41% in 2003. Commercial paper is included in notes payable on the Balance Sheets.
The Company's commercial paper program is supported by the Facility. The Facility was structured to accommodate commercial paper, and the conditions that
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the Company must meet to reserve against the Facility for a project-specific commercial paper issue are the same as those for a regular draw on the Facility. The Company is not likely to be restricted from making draws on the Facility to repay any commercial paper coming due, as those conditions include representations and warranties that do not contain any material adverse effect clauses or creditworthiness measures.
Financial Instruments
The Company enters into energy related derivatives to limit 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. The Company may enter into interest rate swaps to limit exposure to interest rate changes. Swaps related to variable rate securities or forecasted transactions are accounted for as cash flow hedges. These swaps are generally structured to mirror the terms of the hedged debt instruments; therefore, no material ineffectiveness has been recorded in earnings. At December 31, 2003, the Company had no interest derivatives outstanding.
In July 2003, the Company terminated $500 million notional amount of interest rates swaps for losses of $93.3 million at the same time it issued senior notes. In June 2002, the Company settled interest rates swaps for losses of $16.9 million associated with senior notes issued in 2002. These losses have been deferred in other comprehensive income and will be amortized to interest expense over the life of the senior notes.
During 2003, approximately $5.5 million of pre-tax losses were reclassified from other comprehensive income to interest expense. During 2004, approximately $10.4 million of pre-tax losses are expected to be reclassified from other comprehensive income to interest expense.
At December 31, 2003, the fair value of derivative energy contracts was reflected in the financial statements as follows:
Amounts ------------------------------------------------------------------- (in thousands) Other comprehensive income $1.0 Net income (0.3) - ------------------------------------------------------------------- Total fair value $0.7 ===================================================================
For the Company, the fair value gains or losses for cash flow hedges are recorded in other comprehensive income and are reclassified into earnings at the same time the hedged items affect earnings. For 2003, approximately $0.2 million of pre-tax gains were reclassified from other comprehensive income to depreciation and amortization. For 2004, approximately $1.4 million of pre-tax gains are expected to be reclassified from other comprehensive income to earnings.
7. COMMITMENTS
Construction Program
The Company currently estimates property additions to be $259 million, $254 million and $355 million in 2004, 2005 and 2006, respectively. The Company has approximately 1,240 megawatts of additional generating capacity scheduled to be placed in service by 2005.
Significant purchase commitments are outstanding in connection with the construction program.
The Company has obligations related to the construction, by Alabama Power and Georgia Power, of transmission interconnection facilities to these plants, which are guaranteed by Southern Company. At December 31, 2003 these guarantees totaled $17.5 million.
Long-Term Service Agreements
The Company has entered into several Long-Term Service Agreements (LTSAs) with General Electric (GE) for the purpose of securing maintenance support for its combined cycle and combustion turbine generating facilities. In summary, the LTSAs stipulate 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, except for Plant Dahlberg, these LTSAs are in effect through two major inspection cycles per unit. The Dahlberg agreement is in effect through the first major inspection of each unit. Scheduled payments to GE are made at various intervals based on actual operating hours of the respective units. Total payments to GE under these agreements are $831 million over the remaining life of the agreements, which may range up to 30 years per unit.
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However, the LTSAs contain various cancellation provisions at the Company's option.
Payments made to GE prior to the performance of any planned inspections are recorded as a long term prepayment in the Deferred Charges and Other Assets section of the Balance Sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed.
Fuel Commitments
SCS, as agent for the retail operating companies, and Southern Power, 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 New York Mercantile future prices at December 31, 2003.
Fuel Purchases Year (in thousands) - ---- ------------------
2004 $95,194 2005 53,138 2006 47,831 2007 37,426 2008 18,589 2009 and beyond 430,818 - --------------------------------------------------------------- Total $682,996 ===============================================================
Purchases of natural gas were approximately $139.1 million, $133.5 million, and $4.4 million for the periods ended December 31, 2003, 2002, and 2001, respectively. Additional commitments for fuel will be required to supply the Company's future needs.
Acting as an agent for all of Southern Company's retail operating companies, Southern Power and Southern Company GAS, SCS may enter into various types of wholesale energy and natural gas contracts. Under these agreements, each of the retail operating companies, Southern Power and Southern Company GAS may be jointly and severally liable. The creditworthiness of Southern Power and Southern Company GAS is currently inferior to the creditworthiness of the retail operating companies; therefore, Southern Company has entered into keep-well agreements with each of the retail operating companies to insure they will not subsidize nor be responsible for any costs, losses, liabilities or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.
8. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for 2003 and 2002 is as follows:
- --------------------------------------------------------------------- Operating Operating Quarter Ended Revenues Income Net Income - --------------------------------------------------------------------- (in millions) -------------------------------------------- March 2003 $107,439 $ 38,217 $ 23,125 June 2003 238,281 132,421 79,290 September 2003 208,624 68,005 40,139 December 2003 127,436 34,662 12,595
March 2002 $ 19,299 $ 7,862 $ 4,455 June 2002 57,777 16,271 8,858 September 2002 136,195 45,298 27,329 December 2002 85,497 26,764 13,628
The Company's business is influenced by seasonal weather conditions. The Company had approximately 2,400 megawatts of generating capacity in service through May 2002; approximately 2,400 megawatts through May 2003; approximately 4,350 megawatts through September 2003; and 4,775 megawatts through December 2003. During the second quarter of 2003, the Company recorded $80 million of contract termination revenues, as a result of the termination of Dynegy's PPAs related to Plants Dahlberg and Franklin, which resulted in a one-time gain of $50 million. See Note 3 to the financial statements under "Uncontracted Generating Capacity" for additional information.
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PART III
Items 10, 11, 12, 13 and 14 for Southern Company are incorporated by reference in Southern Company's definitive Proxy Statement relating to the 2004 Annual Meeting of Stockholders. Specifically, reference is made to "Nominees for Election as Directors" for Item 10, "Executive Compensation" for Item 11, "Stock Ownership Table" for Item 12, "Certain Relationships and Related Transactions" for Item 13 and "Principal Public Accounting Firm Fees" for Item 14.
Additionally, Items 10, 11, 12, 13 and 14 for Alabama Power, Georgia Power, Gulf Power and Mississippi Power are incorporated by reference to the Information Statements of Alabama Power, Georgia Power, Gulf Power and Mississippi Power relating to each of their respective 2004 Annual Meetings of Shareholders. Specifically, reference is made to "Nominees for Election as Directors" for Item 10, "Executive Compensation Information" for Item 11, "Stock Ownership Table" for Item 12, "Certain Relationships and Related Transactions" for Item 13 and "Principal Public Accounting Firm Fees" for Item 14.
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
The ages of directors and executive officers set forth below are as of December 31, 2003.
SAVANNAH ELECTRIC
Identification of directors of Savannah Electric.
Anthony R. James President and Chief Executive Officer Age 53 Served as Director since 5-3-01
Gus H. Bell, III (1) Age 66 Served as Director since 7-20-99
Archie H. Davis (1) Age 62 Served as Director since 2-18-97
Walter D. Gnann (1) Age 68 Served as Director since 5-17-83
Robert B. Miller, III (1) Age 58 Served as Director since 5-17-83
Arnold M. Tenenbaum (1) Age 67 Served as Director since 5-17-77
(1) No position other than Director.
Each of the above is currently a director of Savannah Electric, serving a term running from the last annual meeting of Savannah Electric's stockholder (May 2, 2003) 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 was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of Savannah Electric acting solely in their capacities as such.
Identification of executive officers of Savannah Electric.
Anthony R. James President, Chief Executive Officer and Director Age 53 Served as Executive Officer since 7-27-00
W. Miles Greer Vice President Age 60 Served as Executive Officer since 11-20-85
Sandra R. Miller Vice President Age 51 Served as Executive Officer since 7-26-01
Kirby R. Willis Vice President, Treasurer and Chief Financial Officer Age 52 Served as Executive Officer since 1-1-94
Each of the above is currently an executive officer of Savannah Electric, serving a term running from the meeting of the directors held on July 24, 2003 for the ensuing year.
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
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selected as an officer, other than any arrangements or understandings with officers of Savannah Electric acting solely in their capacities as such.
Identification of certain significant employees. None.
Family relationships. None.
Business experience.
Anthony R. James - President and Chief Executive Officer since 2001. Previously served as Vice President of Power Generation and Senior Production Officer from 2000 to 2001; Central Cluster Manager at Georgia Power's Plant Scherer from 2000 to 2001; and Plant Manager at Georgia Power's Plant Scherer from 1996 to 2000. He is a director of SunTrust Bank of Savannah.
Gus H. Bell, III - President and Chief Executive Officer of Hussey, Gay, Bell and DeYoung, Inc., (specializing in environmental, industrial, structural, architectural and civil engineering), Savannah, Georgia since 1986. He is a director of SunTrust Bank of Savannah.
Archie H. Davis - President, Chief Executive Officer and Director of Savannah Bancorp, Inc., Savannah, Georgia since 1990 and Vice Chairman and Director of The Savannah Bank, N.A. since January 2003. Previously served as Chief Executive Officer of The Savannah Bank, N.A. from 2002 to 2003 and as President and Chief Executive Officer of The Savannah Bank, N.A. from 1990 to 2002. He is a director of Bryan Bank and Trust, Savannah, Georgia.
Walter D. Gnann - President of Walt's TV, Appliance and Furniture Co., Inc., Springfield, Georgia since 1958.
Robert B. Miller, III - President of American Building Systems, Inc. (general contracting services), Savannah, Georgia since 1992.
Arnold M. Tenenbaum - Retired from Chatham Steel Corporation in 2003. Previously served as President and Director of Chatham Steel Corporation (specializing in carbon, stainless and specialty steel), Savannah, Georgia from 2001 to 2003; and served as President and Chief Executive Officer of Chatham Steel Corporation from 1981 to 2001. Chairman of the Board of Directors of the holding company of First Chatham Bank, Savannah, Georgia.
W. Miles Greer - Vice President of Customer Operations and External Affairs since 1998. Previously served as Vice President of Marketing and Customer Service from 1994 to 1998.
Sandra R. Miller - Vice President of Power Generation since 2001. Previously served as Manager of Technical Training at SCS from 1998 to 2001.
Kirby R. Willis - Vice President, Treasurer and Chief Financial Officer since 1994 and Assistant Corporate Secretary since 1998.
Involvement in certain legal proceedings. None.
Section 16(a) Beneficial Ownership Reporting Compliance.
No reporting person of Savannah Electric failed to file, on a timely basis, the reports required by Section 16(a).
III-2
SOUTHERN POWER
Identification of directors of Southern Power.
W. Paul Bowers President and Chief Executive Officer Age 47 Served as Director since 5-1-01
H. Allen Franklin (1) (2) Age 59 Served as Director since 1-8-01
Thomas A. Fanning (1) Age 46 Served as Director since 4-11-03
Charles D. McCrary (1) Age 52 Served as Director since 2-11-02 and also served as Director from 1-8-01 to 4-16-01
David M. Ratcliffe (1) (2) Age 55 Served as Director since 1-8-01
(1) Each of the above is employed within the Southern Company system; however, each holds no position at Southern Power other than Director.
(2) Mr. Franklin will retire in July 2004. Mr. Ratcliffe will become Chief Executive Officer of Southern Company in July 2004.
Each of the above is currently a director of Southern Power, serving a term running from the last annual meeting of Southern Power's stockholder (April 11, 2003) 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 was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of Southern Power acting solely in their capacities as such.
Identification of executive officers of Southern Power.
W. Paul Bowers President and Chief Executive Officer Age 47 Served as Executive Officer since 5-1-01
Robert G. Moore Senior Vice President Age 54 Served as Executive Officer since 1-4-02
Edward Day Senior Vice President Age 43 Served as Executive Officer since 5-7-03
Douglas E. Jones Senior Vice President Age 45 Served as Executive Officer since 1-1-04
Anthony J. Topazi (1) Senior Vice President Age 53 Served as Executive Officer since 3-1-01
Cliff S. Thrasher Senior Vice President, Comptroller and Chief Financial Officer Age 53 Served as Executive Officer since 6-10-02
(1) Mr. Topazi was elected President, Chief Executive Officer and Director of Mississippi Power effective January 1, 2004 and resigned as Senior Vice President of Southern Power effective January 1, 2004.
Except for Mr. Topazi, each of the above is currently an executive officer of Southern Power, serving a term running from the meeting of the directors held on May 7, 2003 for one year until the next annual meeting or until their successors are elected and have qualified, except for Mr. Jones whose election was effective on the date indicated.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as an officer, other than any arrangements or understandings with officers of Southern Power acting solely in their capacities as such.
Identification of certain significant employees. None.
Family relationships. None.
III-3
Business experience.
W. Paul Bowers - President, Chief Executive Officer and Director since May 2001; Executive Vice President of SCS since May 2001. Previously served as Senior Vice President of SCS and Chief Marketing Officer of Southern Company from March 2000 to May 2001; President and Chief Executive Officer of Western Power Distribution, a subsidiary of Mirant located in Bristol, England from December 1998 to 2000.
Edward Day - Senior Vice President since May 2003. Previously served as Vice President of Business Development, Southern Company Generation and Energy Marketing from 1998 to 2003.
Thomas A. Fanning - Executive Vice President, Chief Financial Officer and Treasurer of Southern Company since April 11, 2003. Previously served as President, Chief Executive Officer and Director of Gulf Power from May 2002 to April 2003; Executive Vice President, Treasurer and Chief Financial Officer of Georgia Power from 1999 to 2002.
H. Allen Franklin - Chairman, President and Chief Executive Officer of Southern Company since April 2001. Previously served as President and Chief Executive Officer from March 2001 to April 2001; President and Chief Operating Officer of Southern Company from June 1999 to March 2001; and Executive Vice President of Southern Company and President and Chief Executive Officer of Georgia Power from January 1994 to June 1999. He is a director of SouthTrust Corporation, Vulcan Materials Company, and Southern Company system companies - Southern Company, Alabama Power, Georgia Power and Gulf Power.
Douglas E. Jones - Senior Vice President since January 2004. Previously served as Senior Vice President, Southern Company Energy Marketing from December 2001 to January 2004; and Vice President, Southern Company Wholesale Energy from December 1998 to 2001.
Charles D. McCrary - Executive Vice President of Southern Company since February 2002 and President and Chief Executive Officer of Alabama Power since October 2001. Previously served as President and Chief Operating Officer of Alabama Power from April 2001 to October 2001; Vice President of Southern Company from February 1998 to April 2001; and Executive Vice President of Alabama Power from April 1994 to February 1998. He is a director of Alabama Power and AmSouth Bancorporation.
Robert G. Moore - Senior Vice President since January 2002 and Vice President of SCS since August 1997. Previously served as Vice President of Gulf Power from July 1997 to May 2002.
David M. Ratcliffe - Current Chief Executive Officer of Georgia Power and to become Chief Executive Officer of Southern Company in July 2004. Executive Vice President of Southern Company since 1999 and President and Chief Executive Officer of Georgia Power since June 1999. Previously served as Executive Vice President, Treasurer and Chief Financial Officer of Georgia Power from March 1998 to June 1999. He is a director of Georgia Power; Mississippi Chemical Company; Federal Reserve Bank of Atlanta and CSX Corporation.
Cliff S. Thrasher - Senior Vice President, Comptroller and Chief Financial Officer of Southern Power since November 2002 and Vice President of SCS since June 2002. Previously served as Vice President, Comptroller and Chief Financial Officer of Southern Power from June 2002 to November 2002 and Vice President, Comptroller and Chief Accounting Officer of Georgia Power from September 1995 to June 2002.
Anthony J. Topazi - President and Chief Executive Officer of Mississippi Power since January 2004. Previously served as Senior Vice President of Southern Power from November 2002 to December 2003 and Vice President of SCS from December 1999 to December 2003; Vice President of Southern Power from March 2001 until November 2002 and Vice President of Alabama Power from March 1991 to December 1999.
Section 16(a) Beneficial Ownership Reporting Compliance.
Not applicable.
III-4
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 http://www.southerncompany.com. The code of business conduct and ethics is also available in print to any shareholder upon request. 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 Guidelines
Southern Company has adopted corporate governance guidelines. The corporate governance guidelines and the charters of Southern Company's audit committee, corporate governance and nominating committee and compensation committee can be found on Southern Company's website located at http://www.southerncompany.com. The corporate governance guidelines and charters are also available in print to any shareholder upon request.
III-5
Item 11.
Item 11. EXECUTIVE COMPENSATION
Summary Compensation Table. The following table sets forth information concerning any Chief Executive Officer and the three most highly compensated executive officers of Savannah Electric serving during 2003.
- -----------------------------------
1 Tax reimbursement on certain personal benefits. 2 Payout of performance dividend equivalents on stock options granted after 1996 that were held by the executive at the end of the performance periods under the Omnibus Incentive Compensation Plan for the four-year performance periods ended December 31, 2001, 2002 and 2003, respectively. Dividend equivalents can range from 25 percent of the common stock dividend paid during the last year of the performance period if total shareholder return over the four-year period, compared to a group of other large utility companies, is at the 30th percentile to 100 percent of the dividend paid if it reaches the 90th percentile. For eligible stock options held on December 31, 2001, 2002 and 2003, all named executives received a payout of $1.34, $1.355 and $1.385 per option, respectively. 3 Contributions in 2003 to the Employee Savings Plan (ESP), Employee Stock Ownership Plan (ESOP) and Supplemental Benefit Plan (SBP) or Above-Market Earnings on deferred compensation (AME) are as follows:
Name ESP ESOP SBP or AME - ---- --- ---- ---------- Anthony R. James $7,967 $744 $3,245 W. Miles Greer 8,921 744 12,037 Kirby R. Willis 6,719 636 7,279 Sandra R. Miller 5,403 744 1,277 In 2003, these amounts included additional incentive compensation of $5,000 and $3,000 for Ms. Miller and Mr. Greer, respectively. 4 Mr. James became President and Chief Executive Officer effective in May 2001. 5 Ms. Miller became an executive officer of Savannah Electric in July 2001.
III-6
Summary Compensation Table. The following table sets forth information concerning any Chief Executive Officer and the four most highly compensated executive officers of Southern Power serving during 2003.
- --------------------------------------- 6 Tax reimbursement on certain personal benefits. 7 Payout of performance dividend equivalents on stock options granted after 1996 that were held by the executive at the end of the performance periods under the Omnibus Incentive Compensation Plan for the four-year performance periods ended December 31, 2001, 2002 and 2003, respectively. Dividend equivalents can range from 25 percent of the common stock dividend paid during the last year of the performance period if total shareholder return over the four-year period, compared to a group of other large utility companies, is at the 30th percentile to 100 percent of the dividend paid if it reaches the 90th percentile. For eligible stock options held on December 31, 2001, 2002 and 2003, all named executives received a payout of $1.34, $1.355 and $1.385 per option, respectively. 8 Contributions in 2003 to the Employee Savings Plan (ESP), Employee Stock Ownership Plan (ESOP), Supplemental Benefit Plan (SBP) and tax sharing benefits paid to participants who elected receipt of dividends on Southern Company's common stock held in the ESP are as follows:
Name ESP ESOP SBP ESP Tax Sharing Benefits - ---- --- ---- --- ------------------------ W. Paul Bowers $7,934 $744 $9,385 $ - Anthony J. Topazi 9,000 744 4,851 - Robert G. Moore 7,934 744 2,519 788 Cliff S. Thrasher 9,000 744 885 - Edward Day 8,215 744 543 - In 2003, these amounts include additional incentive compensation of $40,000, $7,000 and $20,000 for Messrs. Topazi, Moore and Day, respectively. In 2002, these amounts include additional incentive compensation of $50,000 each for Mr. Topazi and Mr. Thrasher. In 2001, these amounts included additional incentive compensation for Messrs. Bowers and Topazi of $24,380 and $200,000 respectively. 9 Mr. Moore became an executive officer of Southern Power in January 2002 and Mr. Thrasher became an executive officer of Southern Power in June 2002. 10 Mr. Day became an executive officer of Southern Power in May 2003.
III-7
STOCK OPTION GRANTS IN 2003
Stock Option Grants. The following table sets forth all stock option grants to the named executive officers of Savannah Electric and Southern Power during the year ending December 31, 2003.
III-8
AGGREGATED STOCK OPTION EXERCISES IN 2003 AND YEAR-END OPTION VALUES
Aggregated Stock Option Exercises. The following table sets forth information concerning options exercised during the year ending December 31, 2003 by the named executive officers and the value of unexercised options held by them as of December 31, 2003.
III-9
DEFINED BENEFIT OR ACTUARIAL PLAN DISCLOSURE
Pension Plan Table. The following table sets forth the estimated annual pension benefits payable at normal retirement age under Southern's qualified Pension Plan, as well as non-qualified supplemental benefits, based on the stated compensation and years of service with the Southern Company system for all named executive officers of Savannah Electric and Southern Power, except for Messrs. Greer and Willis. Compensation for pension purposes is limited to the average of the highest three of the final 10 years' compensation. Compensation is base salary plus the excess of annual incentive compensation over 15 percent of base salary. These compensation components are reported under columns titled "Salary" and "Bonus" in the Summary Compensation Tables on pages III-6 and III-7.
As of December 31, 2003, the applicable compensation levels and years of accredited service are presented in the following tables:
Savannah Electric Compensation Accredited Name Level Years of Service ------------ ----------------
Anthony R. James $382,476 24 W. Miles Greer 16 263,274 27 Kirby R. Willis 17 243,194 29 Sandra R. Miller 218,099 23
Southern Power
Compensation Accredited Name Level Years of Service ------------ ----------------
W. Paul Bowers $650,994 23 Anthony J. Topazi 460,397 33 Robert G. Moore 388,047 29 Cliff S. Thrasher 324,619 32 Edward Day 279,250 19
16 The number of accredited years of service includes 7 years and 6 months credited to Mr. Greer pursuant to a supplemental pension agreement. 17 The number of accredited years of service includes 5 years and 5 months granted to Mr. Willis for time served at a non-affiliated electric utility.
III-10
The amounts shown in the table were calculated according to the final average pay formula and are based on a single life annuity without reduction for joint and survivor annuities or computation of Social Security offset that would apply in most cases.
In 1998, Savannah Electric merged its pension plan into the Southern Company Pension Plan. Savannah Electric also has in effect a supplemental executive retirement plan for certain of its executive employees. The plan is designed to provide participants with a supplemental retirement benefit, which, in conjunction with Social Security and benefits under Southern Company's qualified pension plan, will equal 70 percent of the highest three of the final 10 years' average annual earnings (excluding incentive compensation).
The following table sets forth the estimated combined annual pension benefits under Southern Company's pension and Savannah Electric's supplemental executive retirement plans in effect during 2003 which are payable to Messrs. Greer and Willis, upon retirement at the normal retirement age after designated periods of accredited service and at a specified compensation level.
Years of Accredited Service --------------------------------------------------- Remuneration 15 25 35 - ---------------------- -- -- --
$150,000 $105,000 $105,000 $105,000 180,000 126,000 126,000 126,000 210,000 147,000 147,000 147,000 260,000 182,000 182,000 182,000 280,000 196,000 196,000 196,000 300,000 210,000 210,000 210,000 350,000 245,000 245,000 245,000 400,000 280,000 280,000 280,000 430,000 301,000 301,000 301,000 460,000 322,000 322,000 322,000
Compensation of Directors.
Standard Arrangements. The following table presents compensation paid to Savannah Electric's directors during 2003 for service as a member of the board of directors and any board committee(s), except that employee directors received no fees or compensation for service as a member of the board of directors or any board committee. At the election of the director, all or a portion of the cash retainer may be payable in Southern Company's common stock, and all or a portion of the total fees may be deferred under the Deferred Compensation Plan until membership on the board is terminated.
Cash Retainer Fee $10,000 Stock Retainer Fee 85 shares per quarter Meeting Fee $750 for each Board or Committee meeting attended
Southern Power's directors are all employed within the Southern Company system and receive no fees or compensation for service as a member of Southern Power's board of directors.
Other Arrangements. No director received other compensation for services as a director during the year ending December 31, 2003 in addition to or in lieu of that specified by the standard arrangements specified above.
III-11
Employment Contracts and Termination of Employment and Change in Control Arrangements. - ------------------------------------------------------------------------
Southern Power's executive officers are employees of SCS. Savannah Electric and SCS have adopted Southern Company's Change in Control Plan, which is applicable to certain of its officers, and has entered into individual change in control agreements with its most highly compensated executive officers. If an executive is involuntarily terminated, other than for cause, within two years following a change in control of Savannah Electric, SCS or Southern Company, the agreements provide for:
o lump sum payment of two or three times annual compensation, o up to five years' coverage under group health and life insurance plans, o immediate vesting of all stock options, stock appreciation rights and restricted stock previously granted, o payment of any accrued long-term and short-term bonuses and dividend equivalents and o payment of any excise tax liability incurred as a result of payments made under any individual agreements.
A change in control is defined under the agreements as:
o acquisition of at least 20 percent of the Southern Company's stock, o a change in the majority of the members of the Southern Company's board of directors, o a merger or other business combination that results in Southern Company's shareholders immediately before the merger owning less than 65 percent of the voting power after the merger or o a sale of substantially all the assets of Southern Company.
A change in control of Savannah Electric is defined under the agreements as:
o acquisition of at least 50 percent of Savannah Electric's stock, o a merger or other business combination unless Southern Company controls the surviving entity or o a sale of substantially all the assets of Savannah Electric.
Southern Company also has amended its short- and long-term incentive plans to provide for pro-rata payments at not less than target-level performance if a change in control occurs and the plans are not continued or replaced with comparable plans.
Mr. W. Miles Greer and Savannah Electric entered into agreements that provide for a monthly payment to Mr. Greer after his retirement equal to the difference between the amount he will receive under the Southern Company Pension Plan and Savannah Electric Supplemental Executive Retirement Plan and the amount he would receive under those Plans had he been employed by Savannah Electric an additional seven years and six months under the Pension Plan and an additional eight years under the Supplemental Executive Retirement Plan.
Report on Repricing of Options. - -------------------------------
None.
Compensation Committee Interlocks and Insider Participation. - ------------------------------------------------------------
None.
III-12
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 Savannah Electric and Southern Power.
Security Ownership of Management. The following table shows the number of shares of Southern Company Common stock owned by the directors, nominees and executive officers as of December 31, 2003. 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, 2003.
III-13
Changes in control. Southern Company, Savannah Electric and Southern Power know of no arrangements which may at a subsequent date result in any change in control.
III-14
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
SAVANNAH ELECTRIC
Transactions with management and others.
Mr. Archie Davis is currently President, Chief Executive Officer and a Director of Savannah Bancorp, Inc. and Vice Chairman and Director of The Savannah Bank, N.A., Savannah, Georgia and was also President and Chief Executive Officer prior to January 2003. Messrs. James and Bell are directors of SunTrust Bank of Savannah. Mr. Tenenbaum is Chairman of the Board of Directors for the holding company of First Chatham Bank. During 2003, these banks furnished a number of regular banking services in the ordinary course of business to Savannah Electric. Savannah Electric intends to maintain normal banking relations with the aforesaid banks in the future.
Certain business relationships. None.
Indebtedness of management. None.
Transactions with promoters. None.
SOUTHERN POWER
Transactions with management and others. None.
Certain business relationships. None.
Indebtedness of management. None.
Transactions with promoters. None.
III-15
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following represents the fees billed to Savannah Electric and Southern Power for the last two fiscal years by Deloitte & Touche LLP, each company's principal public accountant for 2003 and 2002:
(1) Includes services performed in connection with financing transactions. (2) Includes internal control review services and accounting consultations. (3) 2002 amount includes a re-audit of the 2001 financial statements and other services performed in connection with Southern Power's initial public debt offering. 2003 amount includes services performed in connection with additional financing transactions.
The Southern Company Audit Committee (on behalf of Southern Company and all 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 the fiscal year 2003 (described in the footnotes to the table above) and related fees were approved in advance by the Southern Company Audit Committee.
III-16
PART IV
Item 15.
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this report on this Form 10-K:
(1) Financial Statements:
Independent Auditors' Reports on the financial statements for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and Southern Power 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, Savannah Electric and Southern Power are listed under Item 8 herein.
Reports of Independent Public Accountants on the financial statements for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric are listed under Item 8 herein.
(2) Financial Statement Schedules:
Independent Auditors' Reports as to Schedules for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and Southern Power are included herein on pages IV-9, IV-11, IV-13, IV-15, IV-17, IV-19 and IV-21.
Financial Statement Schedules for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and Southern Power are listed in the Index to the Financial Statement Schedules at page S-1.
Reports of Independent Public Accountants as to Schedules for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric are included herein on pages IV-10, IV-12, IV-14, IV-16, IV-18 and IV-20.
(3) Exhibits:
Exhibits for Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and Southern Power are listed in the Exhibit Index at page E-1.
(b) Reports on Form 8-K during the fourth quarter of 2003 were as follows:
The registrants collectively and separately furnished a Current Report on Form 8-K:
Date of event: October 21, 2003 Item reported: 12
The registrants collectively and separately filed Current Reports on Form 8-K:
Date of event: December 2, 2003 Items reported: 5 and 7
Date of event: December 8, 2003 Item reported: 5
Southern Company and Mississippi Power collectively and separately filed Current Reports on Form 8-K:
Date of event: December 16, 2003 Item reported: 5
Alabama Power filed a Current Report on Form 8-K:
Date of event: November 14, 2003 Items reported: 5 and 7
Savannah Electric filed a Current Report on Form 8-K:
Date of event: December 10, 2003 Items reported: 5 and 7
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.
THE SOUTHERN COMPANY
By: H. Allen Franklin, Chairman, President and Chief Executive Officer
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
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.
H. Allen Franklin Chairman, President and Chief Executive Officer (Principal Executive Officer)
Thomas A. Fanning Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
W. Dean Hudson Comptroller and Chief Accounting Officer (Principal Accounting Officer)
Directors: Daniel P. Amos Zack T. Pate Dorrit J. Bern J. Neal Purcell Thomas F. Chapman David M. Ratcliffe Bruce Gordon Gerald J. St. Pe' Donald M. James
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
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: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
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)
William B. Hutchins, III Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
Art P. Beattie Vice President and Comptroller (Principal Accounting Officer)
Directors: Whit Armstrong Malcolm Portera David J. Cooper Robert D. Powers H. Allen Franklin C. Dowd Ritter R. Kent Henslee James H. Sanford Patricia M. King William F. Walker James K. Lowder John Cox Webb, IV Wallace D. Malone, Jr. James W. Wright
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
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.
GEORGIA POWER COMPANY
By: David M. Ratcliffe, Chief Executive Officer
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
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 Chief Executive Officer and Director (Principal Executive Officer)
C. B. Harreld Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
W. Ron Hinson Vice President, Comptroller and Chief Accounting Officer (Principal Accounting Officer)
Directors: Juanita P. Baranco D. Gary Thompson Robert L. Brown, Jr. Richard W. Ussery Anna R. Cablik William Jerry Vereen H. Allen Franklin Carl Ware Michael D. Garrett E. Jenner Wood, III
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
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.
GULF POWER COMPANY
By: Susan N. Story, President and Chief Executive Officer
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
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, Chief Financial Officer and Comptroller (Principal Financial and Accounting Officer)
Directors: C. LeDon Anchors William A. Pullum William C. Cramer, Jr. Winston E. Scott Fred C. Donovan, Sr.
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
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.
MISSISSIPPI POWER COMPANY
By: Anthony J. Topazi, President and Chief Executive Officer
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
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)
Michael W. Southern Vice President, Treasurer and Chief Financial Officer (Principal Financial and Accounting Officer)
Directors: Tommy E. Dulaney George A. Schloegel Robert C. Khayat Philip J. Terrell Aubrey K. Lucas Gene Warr
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
IV-6
SAVANNAH ELECTRIC AND 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.
SAVANNAH ELECTRIC AND POWER COMPANY
By: Anthony R. James, President and Chief Executive Officer
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
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 R. James President, Chief Executive Officer and Director (Principal Executive Officer)
Kirby R. Willis Vice President, Treasurer and Chief Financial Officer (Principal Financial and Accounting Officer)
Directors: Gus H. Bell, III Robert B. Miller, III Archie H. Davis Arnold M. Tenenbaum Walter D. Gnann
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
IV-7
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.
SOUTHERN POWER COMPANY
By: William P. Bowers, President and Chief Executive Officer
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
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.
William P. Bowers President, Chief Executive Officer and Director (Principal Executive Officer)
Cliff S. Thrasher Senior Vice President, Comptroller and Chief Financial Officer (Principal Financial and Accounting Officer)
Directors: Thomas A. Fanning Charles D. McCrary H. Allen Franklin David M. Ratcliffe
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
IV-8
DELOITTE.
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of Southern Company:
We have audited the consolidated financial statements of Southern Company and Subsidiary Companies as of December 31, 2003 and 2002, and for the years then ended, and have issued our report thereon dated March 1, 2004 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the change in the method of accounting for asset retirement obligations); such consolidated financial statements and report are included elsewhere in this Form 10-K. Our audit also included the 2003 and 2002 consolidated financial statement schedules of Southern Company and Subsidiary Companies (page S-2) listed in the accompanying index at Item 15. These financial statement schedules are the responsibility of Southern Company's management. Our responsibility is to express an opinion based on our audits. The 2001 consolidated financial statement schedule was audited by other auditors who have ceased operations. Those auditors expressed an opinion, in their report dated February 13, 2002, that such 2001 consolidated financial statement schedule, when considered in relation to the 2001 basic consolidated financial statements taken as a whole, presented fairly, in all material respects, the information set forth therein. In our opinion, the 2003 and 2002 consolidated financial statement schedules, when considered in relation to the 2003 and 2002 basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP Atlanta, Georgia March 1, 2004
Member of Deloitte Touche Tohmatsu IV-9
THIS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH THE SOUTHERN COMPANY'S 2001 ANNUAL REPORT AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
To The Southern Company:
We have audited in accordance with auditing standards generally accepted in the United States, the consolidated financial statements of The Southern Company and its subsidiaries included in this Form 10-K, and have issued our report thereon dated February 13, 2002. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates to The Southern Company and its subsidiaries (page S-2) is the responsibility of The Southern Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic consolidated financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole.
/s/ Arthur Andersen LLP
Atlanta, Georgia February 13, 2002
IV-10
DELOITTE.
INDEPENDENT AUDITORS' REPORT
Alabama Power Company:
We have audited the financial statements of Alabama Power Company as of December 31, 2003 and 2002, and for the years then ended, and have issued our report thereon dated March 1, 2004 (which report expresses an unqualified opinion an includes and explanatory paragraph relating to the change in the method of accounting for asset retirement obligations); such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the 2003 and 2002 financial statement schedules of Alabama Power Company (page S-3) listed in the accompanying index at Item 15. These financial statement schedules are the responsibility of Alabama Power Company's management. Our responsibility is to express an opinion based on our audits. The 2001 financial statement schedule was audited by other auditors who have ceased operations. Those auditors expressed an opinion, in their report dated February 13, 2002, that such 2001 financial statement schedule, when considered in relation to the 2001 basic financial statements taken as a whole, presented fairly, in all material respects, the information set forth therein. In our opinion, the 2003 and 2002 financial statement schedules, when considered in relation to the 2003 and 2002 basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP Birmingham, Alabama March 1, 2004
Member of Deloitte Touche Tohmatsu
IV-11
THIS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH ALABAMA POWER COMPANY'S 2001 ANNUAL REPORT AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
To Alabama Power Company:
We have audited in accordance with auditing standards generally accepted in the United States, the financial statements of Alabama Power Company included in this Form 10-K, and have issued our report thereon dated February 13, 2002. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates to Alabama Power Company (page S-3) is the responsibility of Alabama Power Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
/s/ Arthur Andersen LLP
Birmingham, Alabama February 13, 2002
IV-12
DELOITTE.
INDEPENDENT AUDITORS' REPORT
Georgia Power Company:
We have audited the financial statements of Georgia Power Company as of December 31, 2003 and 2002, and for the years then ended, and have issued our report thereon dated March 1, 2004 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the change in the method of accounting for asset retirement obligations); such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the 2003 and 2002 financial statement schedules of Georgia Power Company (page S-4) listed in the accompanying index at Item 15. These financial statement schedules are the responsibility of Georgia Power Company's management. Our responsibility is to express an opinion based on our audits. The 2001 financial statement schedule was audited by other auditors who have ceased operations. Those auditors expressed an opinion, in their report dated February 13, 2002, that such 2001 financial statement schedule, when considered in relation to the 2001 basic financial statements taken as a whole, presented fairly, in all material respects, the information set forth therein. In our opinion, the 2003 and 2002 financial statement schedules, when considered in relation to the 2003 and 2002 basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP Atlanta, Georgia March 1, 2004
Member of Deloitte Touche Tohmatsu
IV-13
THIS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH GEORGIA POWER COMPANY'S 2001 ANNUAL REPORT AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
To Georgia Power Company:
We have audited in accordance with auditing standards generally accepted in the United States, the financial statements of Georgia Power Company included in this Form 10-K, and have issued our report thereon dated February 13, 2002. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates to Georgia Power Company (page S-4) is the responsibility of Georgia Power Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
/s/ Arthur Andersen LLP
Atlanta, Georgia February 13, 2002
IV-14
DELOITTE.
INDEPENDENT AUDITORS' REPORT
Gulf Power Company:
We have audited the financial statements of Gulf Power Company as of December 31, 2003 and 2002, and for the years then ended, and have issued our report thereon dated March 1, 2004 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the change in the method of accounting for asset retirement obligations); such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the 2003 and 2002 financial statement schedules of Gulf Power Company (page S-5) listed in the accompanying index at Item 15. These financial statement schedules are the responsibility of Gulf Power Company's management. Our responsibility is to express an opinion based on our audits. The 2001 financial statement schedule was audited by other auditors who have ceased operations. Those auditors expressed an opinion, in their report dated February 13, 2002, that such 2001 financial statement schedule, when considered in relation to the 2001 basic financial statements taken as a whole, presented fairly, in all material respects, the information set forth therein. In our opinion, the 2003 and 2002 financial statement schedules, when considered in relation to the 2003 and 2002 basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP Atlanta, Georgia March 1, 2004
Member of Deloitte Touche Tohmatsu
IV-15
THIS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH GULF POWER COMPANY'S 2001 ANNUAL REPORT AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
To Gulf Power Company:
We have audited in accordance with auditing standards generally accepted in the United States, the financial statements of Gulf Power Company included in this Form 10-K, and have issued our report thereon dated February 13, 2002. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates to Gulf Power Company (page S-5) is the responsibility of Gulf Power Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
/s/ Arthur Andersen LLP
Atlanta, Georgia February 13, 2002
IV-16
DELOITTE.
INDEPENDENT AUDITORS' REPORT
Mississippi Power Company:
We have audited the financial statements of Mississippi Power Company as of December 31, 2003 and 2002, and for the years then ended, and have issued our report thereon dated March 1, 2004 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the change in the method of accounting for asset retirement obligations); such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the 2003 and 2002 financial statement schedules of Mississippi Power Company (page S-6) listed in the accompanying index at Item 15. These financial statement schedules are the responsibility of Mississippi Power Company's management. Our responsibility is to express an opinion based on our audits. The 2001 financial statement schedule was audited by other auditors who have ceased operations. Those auditors expressed an opinion, in their report dated February 13, 2002, that such 2001 financial statement schedule, when considered in relation to the 2001 basic financial statements taken as a whole, presented fairly, in all material respects, the information set forth therein. In our opinion, the 2003 and 2002 financial statement schedules, when considered in relation to the 2003 and 2002 basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP Atlanta, Georgia March 1, 2004
Member of Deloitte Touche Tohmatsu
IV-17
THIS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH MISSISSIPPI POWER COMPANY'S 2001 ANNUAL REPORT AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
To Mississippi Power Company:
We have audited in accordance with auditing standards generally accepted in the United States, the financial statements of Mississippi Power Company included in this Form 10-K, and have issued our report thereon dated February 13, 2002. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates to Mississippi Power Company (page S-6) is the responsibility of Mississippi Power Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
/s/ Arthur Andersen LLP
Atlanta, Georgia February 13, 2002
IV-18
DELOITTE.
INDEPENDENT AUDITORS' REPORT
Savannah Electric and Power Company:
We have audited the financial statements of Savannah Electric and Power Company as of December 31, 2003 and 2002, and for the years then ended, and have issued our report thereon dated March 1, 2004 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the change in the method of accounting for asset retirement obligations); such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the 2003 and 2002 financial statement schedules of Savannah Electric and Power Company (page S-7) listed in the accompanying index at Item 15. These financial statement schedules are the responsibility of Savannah Electric and Power Company's management. Our responsibility is to express an opinion based on our audits. The 2001 financial statement schedule was audited by other auditors who have ceased operations. Those auditors expressed an opinion, in their report dated February 13, 2002, that such 2001 financial statement schedule, when considered in relation to the 2001 basic financial statements taken as a whole, presented fairly, in all material respects, the information set forth therein. In our opinion, the 2003 and 2002 financial statement schedules, when considered in relation to the 2003 and 2002 basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP Atlanta, Georgia March 1, 2004
Member of Deloitte Touche Tohmatsu
IV-19
THIS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH SAVANNAH ELECTRIC AND POWER COMPANY'S 2001 ANNUAL REPORT AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
To Savannah Electric and Power Company:
We have audited in accordance with auditing standards generally accepted in the United States, the financial statements of Savannah Electric and Power Company included in this Form 10-K, and have issued our report thereon dated February 13, 2002. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates to Savannah Electric and Power Company (page S-7) is the responsibility of Savannah Electric and Power Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
/s/ Arthur Andersen LLP
Atlanta, Georgia February 13, 2002
IV-20
DELOITTE.
INDEPENDENT AUDITORS' REPORT
Southern Power Company
We have audited the financial statements of Southern Power Company as of December 31, 2003 and 2002, and for the years then ended and for the period from January 8, 2001 (inception) to December 31, 2001, and have issued our report thereon dated March 1, 2004; such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the financial statement schedules of Southern Power Company (page S-8), listed in the accompanying index at Item 15. These financial statement schedules are the responsibility of Southern Power Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP Atlanta, Georgia March 1, 2004
Member of Deloitte Touche Tohmatsu
IV-21
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
S-2
S-3
S-4
S-5
S-6
S-7
S-8
EXHIBIT INDEX
The following exhibits indicated by an asterisk (*) preceding the exhibit number are filed herewith. The balance of the exhibits have 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
(a)1 - Composite Certificate of Incorporation of Southern Company, reflecting all amendments thereto through January 5, 1994. (Designated in Registration No. 33-3546 as Exhibit 4(a), in Certificate of Notification, File No. 70-7341, as Exhibit A and in Certificate of Notification, File No. 70-8181, as Exhibit A.)
(a)2 - By-laws of Southern Company as amended effective February 17, 2003, and as presently in effect. (Designated in Southern Company's Form 10-Q for the quarter ended June 30, 2003, File No. 1-3526, as Exhibit 3(a)1.)
Alabama Power
(b)1 - Charter of Alabama Power and amendments thereto through February 17, 2004. (Designated in Registration Nos. 2-59634 as Exhibit 2(b), 2-60209 as Exhibit 2(c), 2-60484 as Exhibit 2(b), 2-70838 as Exhibit 4(a)-2, 2-85987 as Exhibit 4(a)-2, 33-25539 as Exhibit 4(a)-2, 33-43917 as Exhibit 4(a)-2, in Form 8-K dated February 5, 1992, File No. 1-3164, as Exhibit 4(b)-3, in Form 8-K dated July 8, 1992, File No. 1-3164, as Exhibit 4(b)-3, in Form 8-K dated October 27, 1993, File No. 1-3164, as Exhibits 4(a) and 4(b), in Form 8-K dated November 16, 1993, File No. 1-3164, as Exhibit 4(a), in Certificate of Notification, File No. 70-8191, as Exhibit A, in Alabama Power's Form 10-K for the year ended December 31, 1997, File No. 1-3164, as Exhibit 3(b)2, in Form 8-K dated August 10, 1998, File No. 1-3164, as Exhibit 4.4, in Alabama Power's Form 10-K for the year ended December 31, 2000, File No. 1-3164, as Exhibit 3(b)2, in Alabama Power's Form 10-K for the year ended December 31, 2001, File No. 1-3164, as Exhibit 3(b)2, in Form 8-K dated February 5, 2003, File No. 1-3164, as Exhibit 4.4, in Alabama Power's Form 10-Q for the quarter ended March 31, 2003, File No 1-3164, as Exhibit 3(b)1 and in Form 8-K dated February 5, 2004, File No. 1-3164 as Exhibit 4.4.)
(b)2 - By-laws of Alabama Power as amended effective April 25, 2003, and as presently in effect. (Designated in Alabama Power's Form 10-Q for the quarter ended March 31, 2003, File No 1-3164, as Exhibit 3(b)2.)
E-1
Georgia Power
(c)1 - Charter of Georgia Power and amendments thereto through January 16, 2001. (Designated in Registration Nos. 2-63392 as Exhibit 2(a)-2, 2-78913 as Exhibits 4(a)-(2) and 4(a)-(3), 2-93039 as Exhibit 4(a)-(2), 2-96810 as Exhibit 4(a)-2, 33-141 as Exhibit 4(a)-(2), 33-1359 as Exhibit 4(a)(2), 33-5405 as Exhibit 4(b)(2), 33-14367 as Exhibits 4(b)-(2) and 4(b)-(3), 33-22504 as Exhibits 4(b)-(2), 4(b)-(3) and 4(b)-(4), in Georgia Power's Form 10-K for the year ended December 31, 1991, File No. 1-6468, as Exhibits 4(a)(2) and 4(a)(3), in Registration No. 33-48895 as Exhibits 4(b)-(2) and 4(b)-(3), in Form 8-K dated December 10, 1992, File No. 1-6468 as Exhibit 4(b), in Form 8-K dated June 17, 1993, File No. 1-6468, as Exhibit 4(b), in Form 8-K dated October 20, 1993, File No. 1-6468, as Exhibit 4(b), in Georgia Power's Form 10-K for the year ended December 31, 1997, File No. 1-6468, as Exhibit 3(c)2 and in Georgia Power's Form 10-K for the year ended December 31, 2000, File No. 1-6468, as Exhibit 3(c)2.)
(c)2 - By-laws of Georgia Power as amended effective February 19, 2003, and as presently in effect. (Designated in Georgia Power's Form 10-K for the year ended December 31, 2002, File No 1-6468, as Exhibit 3(c)2.)
Gulf Power
(d)1 - Restated Articles of Incorporation of Gulf Power and amendments thereto through February 9, 2001. (Designated in Registration No. 33-43739 as Exhibit 4(b)-1, in Form 8-K dated January 15, 1992, File No. 0-2429, as Exhibit 1(b), in Form 8-K dated August 18, 1992, File No. 0-2429, as Exhibit 4(b)-2, in Form 8-K dated September 22, 1993, File No. 0-2429, as Exhibit 4, in Form 8-K dated November 3, 1993, File No. 0-2429, as Exhibit 4, in Gulf Power's Form 10-K for the year ended December 31, 1997, File No. 0-2429, as Exhibit 3(d)2 and in Gulf Power's Form 10-K for the year ended December 31, 2000, File No. 0-2429, as Exhibit 3(d)2.)
(d)2 - By-laws of Gulf Power as amended effective July 26, 2002, and as presently in effect. (Designated in Gulf Power's Form 10-K for the year ended December 31, 2002, File No 0-2429, as Exhibit 3(d)2.)
Mississippi Power
(e)1 - Articles of Incorporation of Mississippi Power, articles of merger of Mississippi Power Company (a Maine corporation) into Mississippi Power and articles of amendment to the articles of incorporation of Mississippi Power through March 8, 2001. (Designated in Registration No. 2-71540 as Exhibit 4(a)-1, in Form U5S for 1987, File No. 30-222-2, as Exhibit B-10, in Registration No. 33-49320 as Exhibit 4(b)-(1), in Form 8-K dated August 5, 1992, File No. 0-6849, as Exhibits 4(b)-2 and 4(b)-3, in Form 8-K dated August 4, 1993, File No. 0-6849, as Exhibit 4(b)-3, in Form 8-K dated August 18, 1993, File No. 0-6849, as Exhibit 4(b)-3, in Mississippi Power's Form 10-K for the year ended December 31, 1997, File No. 0-6849, as Exhibit 3(e)2 and in Mississippi Power's Form 10-K for the year ended December 31, 2000, File No. 0-6849, as Exhibit 3(e)2.)
E-2
(e)2 - By-laws of Mississippi Power as amended effective February 28, 2001, and as presently in effect. (Designated in Mississippi Power's Form 10-K for the year ended December 31, 2001, File No. 0-6849, as Exhibit 3(e)2.)
Savannah Electric
(f)1 - Charter of Savannah Electric and amendments thereto through December 2, 1998. (Designated in Registration Nos. 33-25183 as Exhibit 4(b)-(1), 33-45757 as Exhibit 4(b)-(2), in Form 8-K dated November 9, 1993, File No. 1-5072, as Exhibit 4(b) and in Savannah Electric's Form 10-K for the year ended December 31, 1998, as Exhibit 3(f)2.)
(f)2 - By-laws of Savannah Electric as amended effective May 17, 2000, and as presently in effect. (Designated in Savannah Electric's Form 10-K for the year ended December 31, 2000, File No. 1-5072, as Exhibit 3(f)2.)
Southern Power
(g)1 - Certificate of Incorporation of Southern Power dated January 8, 2001. (Designated in Registration No. 333-98553 as Exhibit 3.1.)
(g)2 - Bylaws of Southern Power effective January 8, 2001. (Designated in Registration No. 333-98553 as Exhibit 3.2.)
(4) Instruments Describing Rights of Security Holders, Including Indentures
Southern Company
(a)1 - Subordinated Note Indenture dated as of February 1, 1997, among Southern Company, Southern Company Capital Funding, Inc. and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as Trustee, and indentures supplemental thereto dated as of February 4, 1997. (Designated in Registration Nos. 333-28349 as Exhibits 4.1 and 4.2 and 333-28355 as Exhibit 4.2.)
(a)2 - Subordinated Note Indenture dated as of June 1, 1997, among Southern Company, Southern Company Capital Funding, Inc. and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as Trustee, and indentures supplemental thereto through July 31, 2002. (Designated in Southern Company's Form 10-K for the year ended December 31, 1997, File No. 1-3526, as Exhibit (4)(a)2, in Form 8-K dated June 18, 1998, File No. 1-3526, as Exhibit 4.2, in Form 8-K dated December 18, 1998, File No. 1-3526, as Exhibit 4.4 and in Form 8-K dated July 24, 2002, File No. 1-3526, as Exhibit 4.4.)
(a)3 - Senior Note Indenture dated as of February 1, 2002, among Southern Company, Southern Company Capital Funding, Inc. and The Bank of New York, as Trustee, and indentures supplemental thereto through those dated February 1, 2002. (Designated in Form 8-K dated January 29, 2002, File No. 1-3526, as Exhibits 4.1 and 4.2 and in Form 8-K dated January 30, 2002, File No. 1-3526, as Exhibit 4.2.)
E-3
(a)4 - Amended and Restated Trust Agreement of Southern Company Capital Trust I dated as of February 1, 1997. (Designated in Registration No. 333-28349 as Exhibit 4.6.)
(a)5 - Amended and Restated Trust Agreement of Southern Company Capital Trust II dated as of February 1, 1997. (Designated in Registration No. 333-28355 as Exhibit 4.6.)
(a)6 - Amended and Restated Trust Agreement of Southern Company Capital Trust VI dated as of July 1, 2002. (Designated in Form 8-K dated July 24, 2002, File No. 1-3526, as Exhibit 4.7-A.)
(a)7 - Capital Securities Guarantee Agreement relating to Southern Company Capital Trust I dated as of February 1, 1997. (Designated in Registration No. 333-28349 as Exhibit 4.10.)
(a)8 - Capital Securities Guarantee Agreement relating to Southern Company Capital Trust II dated as of February 1, 1997. (Designated in Registration No. 333-28355 as Exhibit 4.10.)
(a)9 - Preferred Securities Guarantee Agreement relating to Southern Company Capital Trust VI dated as of July 1, 2002. (Designated in Form 8-K dated July 24, 2002, File No. 1-3526, as Exhibit 4.11-A.)
Alabama Power
(b)1 - Indenture dated as of January 1, 1942, between Alabama Power and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through December 1, 1994. (Designated in Registration Nos. 2-59843 as Exhibit 2(a)-2, 2-60484 as Exhibits 2(a)-3 and 2(a)-4, 2-60716 as Exhibit 2(c), 2-67574 as Exhibit 2(c), 2-68687 as Exhibit 2(c), 2-69599 as Exhibit 4(a)-2, 2-71364 as Exhibit 4(a)-2, 2-73727 as Exhibit 4(a)-2, 33-5079 as Exhibit 4(a)-2, 33-17083 as Exhibit 4(a)-2, 33-22090 as Exhibit 4(a)-2, in Alabama Power's Form 10-K for the year ended December 31, 1990, File No. 1-3164, as Exhibit 4(c), in Registration Nos. 33-43917 as Exhibit 4(a)-2, 33-45492 as Exhibit 4(a)-2, 33-48885 as Exhibit 4(a)-2, 33-48917 as Exhibit 4(a)-2, in Form 8-K dated January 20, 1993, File No. 1-3164, as Exhibit 4(a)-3, in Form 8-K dated February 17, 1993, File No. 1-3164, as Exhibit 4(a)-3, in Form 8-K dated March 10, 1993, File No. 1-3164, as Exhibit 4(a)-3, in Certificate of Notification, File No. 70-8069, as Exhibits A and B, in Form 8-K dated June 24, 1993, File No. 1-3164, as Exhibit 4, in Certificate of Notification, File No. 70-8069, as Exhibit A, in Form 8-K dated November 16, 1993, File No. 1-3164, as Exhibit 4(b), in Certificate of Notification, File No. 70-8069, as Exhibits A and B, in Certificate of Notification, File No. 70-8069, as Exhibit A, in Certificate of Notification, File No. 70-8069, as Exhibit A and in Form 8-K dated November 30, 1994, File No. 1-3164, as Exhibit 4.)
E-4
(b)2 - Subordinated Note Indenture dated as of January 1, 1996, between Alabama Power and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indenture supplemental thereto dated as of January 1, 1996. (Designated in Certificate of Notification, File No. 70-8461, as Exhibits E and F.)
*(b)3 - Satisfaction and Discharge of Subordinated Note Indenture dated as of April 30, 2003 by JPMorgan Chase Bank, as Trustee, to Alabama Power related to discharging Alabama Power's Subordinated Note Indenture dated as of January 1, 1996, between Alabama Power and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indenture supplemental thereto dated as of January 1, 1996.
(b)4 - Subordinated Note Indenture dated as of January 1, 1997, between Alabama Power and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through October 2, 2002. (Designated in Form 8-K dated January 9, 1997, File No. 1-3164, as Exhibits 4.1 and 4.2, in Form 8-K dated February 18, 1999, File No. 3164, as Exhibit 4.2 and , in Form 8-K dated September 26, 2002, File No. 3164, as Exhibits 4.9-A and 4.9-B.)
(b)5 - Senior Note Indenture dated as of December 1, 1997, between Alabama Power and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through February 17, 2004. (Designated in Form 8-K dated December 4, 1997, File No. 1-3164, as Exhibits 4.1 and 4.2, in Form 8-K dated February 20, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated April 17, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated August 11, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September 8, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September 16, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated October 7, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated October 28, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated November 12, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 19, 1999, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated August 13, 1999, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September 21, 1999, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 11, 2000, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated August 22, 2001, File No. 1-3164, as Exhibits 4.2(a) and 4.2(b), in Form 8-K dated June 21, 2002, File No. 1-3164, as Exhibit 4.2(a), in Form 8-K dated October 16, 2002, File No. 1-3164, as Exhibit 4.2(a), in Form 8-K dated November 20, 2002, File No. 1-3164, as Exhibit 4.2(a), in Form 8-K dated December 6, 2002, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated February 11, 2003, File No. 1-3164, as Exhibits 4.2(a) and 4.2(b), in Form 8-K dated March 12, 2003, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated April 15, 2003, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 1, 2003, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated November 14, 2003, File No. 1-3164, as Exhibit 4.2 and in Form 8-K dated February 10, 2004, File No. 1-3164, as Exhibit 4.2.)
(b)6 - Amended and Restated Trust Agreement of Alabama Power Capital Trust IV dated as of September 1, 2002. (Designated in Form 8-K dated September 26, 2002, File No. 1-3164, as Exhibit 4.12-A.)
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(b)7 - Amended and Restated Trust Agreement of Alabama Power Capital Trust V dated as of September 1, 2002. (Designated in Form 8-K dated September 26, 2002, File No. 1-3164, as Exhibit 4.12-B.)
(b)8 - Guarantee Agreement relating to Alabama Power Capital Trust IV dated as of September 1, 2002. (Designated in Form 8-K dated September 26, 2002, File No. 1-3164, as Exhibit 4.16-A.)
(b)9 - Guarantee Agreement relating to Alabama Power Capital Trust V dated as of September 1, 2002. (Designated in Form 8-K dated September 26, 2002, File No. 1-3164, as Exhibit 4.16-B.)
Georgia Power
(c)1 - Subordinated Note Indenture dated as of August 1, 1996, between Georgia Power and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through January 1, 1997. (Designated in Form 8-K dated August 21, 1996, File No. 1-6468, as Exhibits 4.1 and 4.2 and in Form 8-K dated January 9, 1997, File No. 1-6468, as Exhibit 4.2.)
(c)2 - Subordinated Note Indenture dated as of June 1, 1997, between Georgia Power and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through January 23, 2004. (Designated in Certificate of Notification, File No. 70-8461, as Exhibits D and E, in Form 8-K dated February 17, 1999, File No. 1-6468, as Exhibit 4.4, in Form 8-K dated June 13, 2002, File No. 1-6468, as Exhibit 4.4, in Form 8-K dated October 30, 2002, File No. 1-6468, as Exhibit 4.4 and in Form 8-K dated January 15, 2004, File No. 1-6468, as Exhibit 4.4.)
(c)3 - Senior Note Indenture dated as of January 1, 1998, between Georgia Power and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through February 17, 2004. (Designated in Form 8-K dated January 21, 1998, File No. 1-6468, as Exhibits 4.1 and 4.2, in Forms 8-K each dated November 19, 1998, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated March 3, 1999, File No. 1-6469 as Exhibit 4.2, in Form 8-K dated February 15, 2000, File No. 1-6469 as Exhibit 4.2, in Form 8-K dated January 26, 2001, File No. 1-6469 as Exhibits 4.2(a) and 4.2(b), in Form 8-K dated February 16, 2001, File No. 1-6469 as Exhibit 4.2, in Form 8-K dated May 1, 2001, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated June 27, 2002, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated November 15, 2002, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated February 13, 2003, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated February 21, 2003, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated April 10, 2003, File No. 1-6468, as Exhibits 4.1, 4.2 and 4.3, in Form 8-K dated September 8, 2003, File No. 1-6468, as Exhibit 4.1, in Form 8-K dated September 23, 2003, File No. 1-6468, as Exhibit 4.1, in Form 8-K dated January 12, 2004, File No. 1-6468, as Exhibits 4.1 and 4.2 and in Form 8-K dated February 12, 2004, File No. 1-6468, as Exhibit 4.1.)
(c)4 - Amended and Restated Trust Agreement of Georgia Power Capital Trust IV dated as of February 1, 1999. (Designated in Form 8-K dated February 17, 1999, as Exhibit 4.7-A)
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(c)5 - Amended and Restated Trust Agreement of Georgia Power Capital Trust V dated as of June 1, 2002. (Designated in Form 8-K dated June 13, 2002, as Exhibit 4.7-A.)
(c)6 - Amended and Restated Trust Agreement of Georgia Power Capital Trust VI dated as of November 1, 2002. (Designated in Form 8-K dated October 30, 2002, as Exhibit 4.7-A.)
(c)7 - Amended and Restated Trust Agreement of Georgia Power Capital Trust VII dated as of January 1, 2004. (Designated in Form 8-K dated January 15, 2004, as Exhibit 4.7-A.)
(c)8 - Guarantee Agreement relating to Georgia Power Capital Trust IV dated as of February 1, 1999. (Designated in Form 8-K dated February 17, 1999, as Exhibit 4.11-A.)
(c)9 - Guarantee Agreement relating to Georgia Power Capital Trust V dated as of June 1, 2002. (Designated in Form 8-K dated June 13, 2002, as Exhibit 4.11-A.)
(c)10 - Guarantee Agreement relating to Georgia Power Capital Trust VI dated as of November 1, 2002. (Designated in Form 8-K dated October 30, 2002, as Exhibit 4.11-A.)
(c)11 - Guarantee Agreement relating to Georgia Power Capital Trust VII dated as of January 1, 2004. (Designated in Form 8-K dated January 15, 2004, as Exhibit 4.11-A.)
Gulf Power
(d)1 - Indenture dated as of September 1, 1941, between Gulf Power and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through November 1, 1996. (Designated in Registration Nos. 2-4833 as Exhibit B-3, 2-62319 as Exhibit 2(a)-3, 2-63765 as Exhibit 2(a)-3, 2-66260 as Exhibit 2(a)-3, 33-2809 as Exhibit 4(a)-2, 33-43739 as Exhibit 4(a)-2, in Gulf Power's Form 10-K for the year ended December 31, 1991, File No. 0-2429, as Exhibit 4(b), in Form 8-K dated August 18, 1992, File No. 0-2429, as Exhibit 4(a)-3, in Registration No. 33-50165 as Exhibit 4(a)-2, in Form 8-K dated July 12, 1993, File No. 0-2429, as Exhibit 4, in Certificate of Notification, File No. 70-8229, as Exhibit A, in Certificate of Notification, File No. 70-8229, as Exhibits E and F, in Form 8-K dated January 17, 1996, File No. 0-2429, as Exhibit 4, in Certificate of Notification, File No. 70-8229, as Exhibit A, in Certificate of Notification, File No. 70-8229, as Exhibit A and in Form 8-K dated November 6, 1996, File No. 0-2429, as Exhibit 4.)
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(d)2 - Subordinated Note Indenture dated as of January 1, 1997, between Gulf Power and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through December 13, 2002. (Designated in Form 8-K dated January 27, 1997, File No. 0-2429, as Exhibits 4.1 and 4.2, in Form 8-K dated July 28, 1997, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated January 13, 1998, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated November 8, 2001, File No. 0-2429, as Exhibit 4.2 and in Form 8-K dated December 5, 2002, File No. 0-2429, as Exhibit 4.2.)
(d)3 - Senior Note Indenture dated as of January 1, 1998, between Gulf Power and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through September 16, 2003. (Designated in Form 8-K dated June 17, 1998, File No. 0-2429, as Exhibits 4.1 and 4.2, in Form 8-K dated August 17, 1999, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated July 31, 2001, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated October 5, 2001, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated January 18, 2002, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated March 21, 2003, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated July 10, 2003, File No. 0-2429, as Exhibits 4.1 and 4.2 and in Form 8-K dated September 5, 2003, File No. 0-2429, as Exhibit 4.1.)
(d)4 - Amended and Restated Trust Agreement of Gulf Power Capital Trust III dated as of November 1, 2001. (Designated in Form 8-K dated November 8, 2001, File No. 0-2429, as Exhibit 4.5.)
(d)5 - Amended and Restated Trust Agreement of Gulf Power Capital Trust IV dated as of December 1, 2002. (Designated in Form 8-K dated December 5, 2002, File No. 0-2429, as Exhibit 4.5.)
(d)6 - Guarantee Agreement relating to Gulf Power Capital Trust III dated as of November 1, 2001. (Designated in Form 8-K dated November 8, 1998, File No. 0-2429, as Exhibit 4.8.)
(d)7 - Guarantee Agreement relating to Gulf Power Capital Trust IV dated as of December 1, 2002. (Designated in Form 8-K dated December 5, 2002, File No. 0-2429, as Exhibit 4.8.)
Mississippi Power
(e)1 - Indenture dated as of September 1, 1941, between Mississippi Power and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as Successor Trustee, and indentures supplemental thereto through December 1, 1995. (Designated in Registration Nos. 2-4834 as Exhibit B-3, 2-62965 as Exhibit 2(b)-2, 2-66845 as Exhibit 2(b)-2, 2-71537 as Exhibit 4(a)-(2), 33-5414 as Exhibit 4(a)-(2), 33-39833 as Exhibit 4(a)-2, in Mississippi Power's Form 10-K for the year ended December 31, 1991, File No. 0-6849, as Exhibit 4(b), in Form 8-K dated August 5, 1992, File No. 0-6849, as Exhibit 4(a)-2, in Second Certificate of Notification, File No. 70-7941, as Exhibit I, in Mississippi Power's Form 8-K dated February 26, 1993, File No. 0-6849, as Exhibit 4(a)-2, in Certificate of Notification, File No. 70-8127, as Exhibit A, in Form 8-K dated June 22, 1993, File No. 0-6849, as Exhibit 1, in Certificate of Notification, File
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No. 70-8127, as Exhibit A, in Form 8-K dated March 8, 1994, File No. 0-6849, as Exhibit 4, in Certificate of Notification, File No. 70-8127, as Exhibit C and in Form 8-K dated December 5, 1995, File No. 0-6849, as Exhibit 4.)
(e)2 - Senior Note Indenture dated as of May 1, 1998 between Mississippi Power and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as Trustee and indentures supplemental thereto through April 29, 2003. (Designated in Form 8-K dated May 14, 1998, File No. 0-6849, as Exhibits 4.1, 4.2(a) and 4.2(b), in Form 8-K dated March 22, 2000, File No. 0-6849, as Exhibit 4.2, in Form 8-K dated March 12, 2002, File No. 0-6849, as Exhibit 4.2 and in Form 8-K dated April 24, 2003, File No. 001-11229, as Exhibit 4.2.)
(e)3 - Subordinated Note Indenture dated as of February 1, 1997, between Mississippi Power and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as Trustee, and indenture supplemental thereto dated as of March 22, 2002. (Designated in Form 8-K dated February 20, 1997, File No. 0-6849, as Exhibits 4.1 and 4.2 and in Form 8-K dated March 15, 2002, File No. 0-6849, as Exhibit 4.5.)
(e)4 - Amended and Restated Trust Agreement of Mississippi Power Capital Trust II dated as of March 1, 2002. (Designated in Form 8-K dated March 15, 2002, File No. 0-6849, as Exhibit 4.5.)
(e)5 - Guarantee Agreement relating to Mississippi Power Capital Trust II dated as of March 1, 2002. (Designated in Form 8-K dated March 15, 2002, File No. 0-6849, as Exhibit 4.8.)
Savannah Electric
(f)1 - Indenture dated as of March 1, 1945, between Savannah Electric and The Bank of New York, as Trustee, and indentures supplemental thereto through May 1, 1996. (Designated in Registration Nos. 33-25183 as Exhibit 4(a)-(1), 33-41496 as Exhibit 4(a)-(2), 33-45757 as Exhibit 4(a)-(2), in Savannah Electric's Form 10-K for the year ended December 31, 1991, File No. 1-5072, as Exhibit 4(b), in Form 8-K dated July 8, 1992, File No. 1-5072, as Exhibit 4(a)-3, in Registration No. 33-50587 as Exhibit 4(a)-(2), in Form 8-K dated July 22, 1993, File No. 1-5072, as Exhibit 4, in Form 8-K dated May 18, 1995, File No. 1-5072, as Exhibit 4 and in Form 8-K dated May 23, 1996, File No. 1-5072, as Exhibit 4.)
(f)2 - Senior Note Indenture dated as of March 1, 1998 between Savannah Electric and The Bank of New York, as Trustee and indentures supplemental thereto through December 17, 2003. (Designated in Form 8-K dated March 9, 1998, File No. 1-5072, as Exhibits 4.1 and 4.2, in Form 8-K dated May 8, 2001, File No. 1-5072, as Exhibits 4.2(a) and 4.2(b), in Form 8-K dated March 4, 2002, File No. 1-5072, as Exhibit 4.2, in Form 8-K dated November 4, 2002, File No. 1-5072, as Exhibit 4.2 and in Form 8-K dated December 10, 2003, File No. 1-5072, as Exhibits 4.1 and 4.2.)
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(f)3 - Subordinated Note Indenture dated as of December 1, 1998, between Savannah Electric and The Bank of New York, as Trustee, and indenture supplemental thereto dated as of December 9, 1998. (Designated in Form 8-K dated December 3, 1998, File No. 1-5072, as Exhibit 4.3 and 4.4.)
(f)4 - Amended and Restated Trust Agreement of Savannah Electric Capital Trust I dated as of December 1, 1998. (Designated in Form 8-K dated December 3, 1998, File No. 1-5072, as Exhibit 4.7.)
(f)5 - Guarantee Agreement relating to Savannah Electric Capital Trust I dated as of December 1, 1998. (Designated in Form 8-K dated December 3, 1998, File No. 1-5072, as Exhibit 4.11.)
Southern Power
(g)1 - Indenture dated as of June 1, 2002, between Southern Power and The Bank of New York, as Trustee, and indentures supplemental thereto through July 8, 2003. (Designated in Registration No. 333-98553 as Exhibits 4.1 and 4.2 and in Southern Power's Form 10-Q for the quarter ended June 30, 2003, File No. 333-98553, as Exhibit 4(g)1.)
(10) Material Contracts
Southern Company
(a)1 - Service contracts dated as of January 1, 1984, between SCS and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, SEGCO and Southern Company and Amendment No. 1 dated as of September 6, 1985 between SCS and Southern Company. (Designated in Southern Company's Form 10-K for the year ended December 31, 1984, File No. 1-3526, as Exhibit 10(a) and in Southern Company's Form 10-K for the year ended December 31, 1985, File No. 1-3526, as Exhibit 10(a)(3).)
(a)2 - Service contract dated as of January 1, 2001, between SCS and Southern Power. (Designated in Southern Company's Form 10-K for the year ended December 31, 2001, File No. 1-3526, as Exhibit 10(a)(2).)
(a)3 - Service contract dated as of March 3, 1988, between SCS and Savannah Electric. (Designated in Savannah Electric's Form 10-K for the year ended December 31, 1987, File No. 1-5072, as Exhibit 10-p.)
(a)4 - Service contract dated as of January 15, 1991, between SCS and Southern Nuclear. (Designated in Southern Company's Form 10-K for the year ended December 31, 1991, File No. 1-3526, as Exhibit 10(a)(4).)
(a)5 - Service contract dated as of December 12, 1994, between SCS and Mobile Energy Services Company, Inc. (Designated in Southern Company's Form 10-K for the year ended December 31, 1994, File No. 1-3526, as Exhibit 10(a)58.)
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(a)6 - Interchange contract dated February 17, 2000, between Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power and SCS. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)6.)
(a)7 - Agreement dated as of January 27, 1959, Amendment No. 1 dated as of October 27, 1982 and Amendment No. 2 dated November 4, 1993 and effective June 1, 1994, among SEGCO, Alabama Power and Georgia Power. (Designated in Registration No. 2-59634 as Exhibit 5(c), in Georgia Power's Form 10-K for the year ended December 31, 1982, File No. 1-6468, as Exhibit 10(d)(2) and in Alabama Power's Form 10-K for the year ended December 31, 1994, File No. 1-3164, as Exhibit 10(b)18.)
(a)8 - Joint Committee Agreement dated as of August 27, 1976, among Georgia Power, OPC, MEAG and Dalton. (Designated in Registration No. 2-61116 as Exhibit 5(d).)
(a)9 - Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation Agreement dated as of January 6, 1975, between Georgia Power and OPC. (Designated in Form 8-K for January, 1975, File No. 1-6468, as Exhibit (b)(1).)
(a)10 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as of January 6, 1975, between Georgia Power and OPC. (Designated in Form 8-K for January, 1975, File No. 1-6468, as Exhibit (b)(3).)
(a)11 - Revised and Restated Integrated Transmission System Agreement dated as of November 12, 1990, between Georgia Power and OPC. (Designated in Georgia Power's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(g).)
(a)12 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of March 26, 1976, between Georgia Power and OPC. (Designated in Certificate of Notification, File No. 70-5592, as Exhibit A.)
(a)13 - Plant Hal Wansley Operating Agreement dated as of March 26, 1976, between Georgia Power and OPC. (Designated in Certificate of Notification, File No. 70-5592, as Exhibit B.)
(a)14 - Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation Agreement dated as of August 27, 1976, between Georgia Power, MEAG and Dalton. (Designated in Form 8-K dated as of June 13, 1977, File No. 1-6468, as Exhibit (b)(1).)
(a)15 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as of August 27, 1976, between Georgia Power, MEAG and Dalton. (Designated in Form 8-K for February 1977, File No. 1-6468, as Exhibit (b)(2).)
(a)16 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase and Ownership Participation Agreement dated as of August 27, 1976 and Amendment No. 1 dated as of January 18, 1977, among Georgia Power, OPC, MEAG and Dalton. (Designated in Form U-1, File No. 70-5792, as Exhibit B-1 and in Form 8-K for January 1977, File No. 1-6468, as Exhibit (B)(3).)
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(a)17 - Alvin W. Vogtle Nuclear Units Number One and Two Operating Agreement dated as of August 27, 1976, among Georgia Power, OPC, MEAG and Dalton. (Designated in Form U-1, File No. 70-5792, as Exhibit B-2.)
(a)18 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase, Amendment, Assignment and Assumption Agreement dated as of November 16, 1983, between Georgia Power and MEAG. (Designated in Georgia Power's Form 10-K for the year ended December 31, 1983, File No. 1-6468, as Exhibit 10(k)(4).)
(a)19 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of August 27, 1976, between Georgia Power and MEAG. (Designated in Form 8-K dated as of July 5, 1977, File No. 1-6468, as Exhibit (b)(2).)
(a)20 - Plant Hal Wansley Operating Agreement dated as of August 27, 1976, between Georgia Power and MEAG. (Designated in Form 8-K dated as of July 5, 1977, File No. 1-6468, as Exhibit (b)(4).)
(a)21 - Nuclear Operating Agreement between Southern Nuclear and Georgia Power dated as of July 1, 1993. (Designated in Southern Company's Form 10-K for the year ended December 31, 1997, File No. 1-3526, as Exhibit 10(a)21.)
(a)22 - Pseudo Scheduling and Services Agreement between Georgia Power and MEAG dated as of April 8, 1997. (Designated in Southern Company's Form 10-K for the year ended December 31, 1997, File No. 1-3526, as Exhibit 10(a)22.)
(a)23 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of April 19, 1977, between Georgia Power and Dalton. (Designated in Form 8-K dated as of June 13, 1977, File No. 1-6468, as Exhibit (b)(3).)
(a)24 - Plant Hal Wansley Operating Agreement dated as of April 19, 1977, between Georgia Power and Dalton. (Designated in Form 8-K dated as of June 13, 1977, File No. 1-6468, as Exhibit (b)(7).)
(a)25 - Plant Robert W. Scherer Units Number One and Two Purchase and Ownership Participation Agreement dated as of May 15, 1980, Amendment No. 1 dated as of December 30, 1985, Amendment No. 2 dated as of July 1, 1986, Amendment No. 3 dated as of August 1, 1988 and Amendment No. 4 dated as of December 31, 1990, among Georgia Power, OPC, MEAG and Dalton. (Designated in Form U-1, File No. 70-6481, as Exhibit B-3, in Southern Company's Form 10-K for the year ended December 31, 1987, File No. 1-3526, as Exhibit 10(o)(2), in Southern Company's Form 10-K for the year ended December 31, 1989, File No. 1-3526, as Exhibit 10(n)(2) and in Southern Company's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)54.)
(a)26 - Plant Robert W. Scherer Units Number One and Two Operating Agreement dated as of May 15, 1980, Amendment No. 1 dated as of December 3, 1985 and Amendment No. 2 dated as of December 31, 1990, among Georgia Power, OPC, MEAG and Dalton. (Designated in Form U-1, File No. 70-6481, as Exhibit B-4, in Southern Company's Form 10-K for the year ended December 31, 1987, File No. 1-3526, as Exhibit 10(o)(4) and in Southern Company's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)55.)
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(a)27 - Plant Robert W. Scherer Purchase, Sale and Option Agreement dated as of May 15, 1980, between Georgia Power and MEAG. (Designated in Form U-1, File No. 70-6481, as Exhibit B-1.)
(a)28 - Plant Robert W. Scherer Purchase and Sale Agreement dated as of May 16, 1980, between Georgia Power and Dalton. (Designated in Form U-1, File No. 70-6481, as Exhibit B-2.)
(a)29 - Plant Robert W. Scherer Unit Number Three Purchase and Ownership Participation Agreement dated as of March 1, 1984, Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2 dated as of August 1, 1988, between Georgia Power and Gulf Power. (Designated in Form U-1, File No. 70-6573, as Exhibit B-4, in Southern Company's Form 10-K for the year ended December 31, 1987, as Exhibit 10(o)(2) and in Southern Company's Form 10-K for the year ended December 31, 1989, as Exhibit 10(n)(2).)
(a)30 - Plant Robert W. Scherer Unit Number Three Operating Agreement dated as of March 1, 1984, between Georgia Power and Gulf Power. (Designated in Form U-1, File No. 70-6573, as Exhibit B-5.)
(a)31 - Plant Robert W. Scherer Unit No. Four Amended and Restated Purchase and Ownership Participation Agreement by and among Georgia Power, FP&L and JEA, dated as of December 31, 1990 and Amendment No. 1 dated as of June 15, 1994. (Designated in Form U-1, File No. 70-7843, as Exhibit B-1 and in Southern Company's Form 10-K for the year ended December 31, 1994, File No. 1-3526, as Exhibit 10(a)60.)
(a)32 - Plant Robert W. Scherer Unit No. Four Operating Agreement by and among Georgia Power, FP&L and JEA, dated as of December 31, 1990 and Amendment No. 1 dated as of June 15, 1994. (Designated in Form U-1, File No. 70-7843, as Exhibit B-2 and in Southern Company's Form 10-K for the year ended December 31, 1994, File No. 1-3526, as Exhibit 10(a)61.)
(a)33 - Unit Power Sales Agreement dated July 19, 1988, between FPC and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. (Designated in Savannah Electric's Form 10-K for the year ended December 31, 1988, File No. 1-5072, as Exhibit 10(d).)
(a)34 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. (Designated in Savannah Electric's Form 10-K for the year ended December 31, 1988, File No. 1-5072, as Exhibit 10(e).)
(a)35 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. (Designated in Savannah Electric's Form 10-K for the year ended December 31, 1988, File No. 1-5072, as Exhibit 10(f).)
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(a)36 - Rocky Mountain Pumped Storage Hydroelectric Project Ownership Participation Agreement dated November 18, 1988, between OPC and Georgia Power. (Designated in Georgia Power's Form 10-K for the year ended December 31, 1988, File No. 1-6468, as Exhibit 10(x).)
(a)37 - Rocky Mountain Pumped Storage Hydroelectric Project Operating Agreement dated November 18, 1988, between OPC and Georgia Power. (Designated in Georgia Power's Form 10-K for the year ended December 31, 1988, File No. 1-6468, as Exhibit 10(y).)
(a)38 - Purchase and Ownership Agreement for Joint Ownership Interest in the James H. Miller, Jr. Steam Electric Generating Plant Units One and Two dated November 18, 1988, between Alabama Power and AEC. (Designated in Form U-1, File No. 70-7609, as Exhibit B-1.)
(a)39 - Operating Agreement for Joint Ownership Interest in the James H. Miller, Jr. Steam Electric Generating Plant Units One and Two dated November 18, 1988, between Alabama Power and AEC. (Designated in Form U-1, File No. 70-7609, as Exhibit B-2.)
(a)40 - Transmission Facilities Agreement dated February 25, 1982, Amendment No. 1 dated May 12, 1982 and Amendment No. 2 dated December 6, 1983, between Entergy Corporation (formerly Gulf States) and Mississippi Power. (Designated in Mississippi Power's Form 10-K for the year ended December 31, 1981, File No. 0-6849, as Exhibit 10(f), in Mississippi Power's Form 10-K for the year ended December 31, 1982, File No. 0-6849, as Exhibit 10(f)(2) and in Mississippi Power's Form 10-K for the year ended December 31, 1983, File No. 0-6849, as Exhibit 10(f)(3).)
(a)41 - Long Term Transaction Service Agreement between Georgia Power and OPC dated as of February 26, 1999. (Designated in Southern Company's Form 10-K for the year ended December 31, 1999, File No. 1-3526, as Exhibit 10(a)46.)
(a)42 - Revised and Restated Coordination Services Agreement between and among Georgia Power, OPC and Georgia Systems Operations Corporation dated as of September 10, 1997. (Designated in Southern Company's Form 10-K for the year ended December 31, 1997, File No. 1-3526, as Exhibit 10(a)48.)
(a)43 - Amended and Restated Nuclear Managing Board Agreement for Plant Hatch and Plant Vogtle among Georgia Power, OPC, MEAG and Dalton dated as of July 1, 1993. (Designated in Southern Company's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)49.)
(a)44 - Integrated Transmission System Agreement, Power Sale and Coordination Umbrella Agreement between Georgia Power and OPC dated as of November 12, 1990. (Designated in Georgia Power's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(ff).)
E-14
(a)45 - Revised and Restated Integrated Transmission System Agreement between Georgia Power and Dalton dated as of December 7, 1990. (Designated in Georgia Power's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(gg).)
(a)46 - Revised and Restated Integrated Transmission System Agreement between Georgia Power and MEAG dated as of December 7, 1990. (Designated in Georgia Power's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(hh).)
(a)47 - Long Term Transmission Service Agreement between Entergy Power, Inc. and Alabama Power, Mississippi Power and SCS. (Designated in Southern Company's Form 10-K for the year ended December 31, 1992, File No. 1-3526, as Exhibit 10(a)53.)
(a)48 - Plant Scherer Managing Board Agreement dated as of December 31, 1990 among Georgia Power, OPC, MEAG, Dalton, Gulf Power, FP&L and JEA. (Designated in Southern Company's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)56.)
(a)49 - Plant McIntosh Combustion Turbine Purchase and Ownership Participation Agreement between Georgia Power and Savannah Electric dated as of December 15, 1992. (Designated in Southern Company's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)57.)
(a)50 - Plant McIntosh Combustion Turbine Operating Agreement between Georgia Power and Savannah Electric dated as of December 15, 1992. (Designated in Southern Company's Form 10-K for the year ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)58.)
(a)51 - Operating Agreement for the Joseph M. Farley Nuclear Plant between Alabama Power and Southern Nuclear dated as of December 23, 1991. (Designated in Form U-1, File No. 70-7530, as Exhibit B-7.)
(a)52 - Amended and Restated Credit Agreement among Southern Power, Citibank N.A., as the administrative agent, and the lenders listed therein dated as of April 17, 2003. (Designated in Southern Company's Form 10-Q for the quarter ended March 31, 2003, File No. 1-3526, as Exhibit 10(a)1.)
(a)53 - Completion Guarantee among Southern Company, Southern Power and Citibank, N.A., in its capacity as agent for the Lenders under the Credit Facility dated as of November 15, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.2(a).)
(a)54 - Completion Guarantee Supplement by Southern Company and Southern Power dated as of April 22, 2002. (Designated in Registration No. 333-98553 as Exhibit 10.2(b).)
E-15
(a)55 - Letter Amendment No. 1 to Completion Guarantee among Southern Company, Southern Power and Citibank, N.A. in its capacity as agent for the Lenders under the Credit Facility dated as of April 17, 2003. (Designated in Southern Company's Form 10-Q for the quarter ended March 31, 2003, File No. 1-3526, as Exhibit 10(a)2.)
(a)56 - Equity Contribution Agreement among Southern Company and Citibank, N.A. in its capacity as agent for the Lenders under the Credit Facility dated as of November 15, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.3(a).)
(a)57 - Letter Amendment No. 1 to Equity Contribution Agreement among Southern Company, Southern Power and Citibank, N.A. in its capacity as agent for the Lenders under the Credit Facility dated as of April 17, 2003. (Designated in Southern Company's Form 10-Q for the quarter ended March 31, 2003, File No. 1-3526, as Exhibit 10(a)3.)
(a)58 - Equity Contribution Agreement Supplement by Southern Company and Southern Power dated as of April 22, 2002. (Designated in Registration No. 333-98553 as Exhibit 10.3(b).)
*(a)59 - Amended and Restated Operating Agreement between Southern Power and Alabama Power effective December 1, 2002.
*(a)60 - Amended and Restated Operating Agreement between Southern Power and Georgia Power effective December 1, 2002.
*(a)61 - Operating Agreement between Southern Power and Savannah Electric effective January 1, 2003.
(a)62 - Interconnection Agreement by and between Southern Power and Georgia Power for Plant Dahlberg dated as of July 31, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.8.)
(a)63 - Interconnection Agreement by and between Southern Power and Georgia Power for Wansley CC Units 6 and 7 dated as of May 10, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.9.)
(a)64 - Interconnection Agreement by and between Southern Power and Georgia Power for Goat Rock CC Unit 1 dated as of May 10, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.10.)
(a)65 - Revised and Restated Interconnection Agreement by and between Southern Power and Georgia Power for Goat Rock CC Unit 2 dated as of October 18, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.11.)
(a)66 - Interconnection Agreement by and between Southern Power and Alabama Power for Autaugaville Combined Cycle Unit 1 dated as of June 25, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.12.)
E-16
(a)67 - Interconnection Agreement by and between Southern Power and Alabama Power for Autaugaville Combined Cycle Unit 2 dated as of June 25, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.13.)
(a)68 - Purchased Power Agreement between Georgia Power and LG&E Energy Marketing Inc. dated as of November 24, 1998. (Designated in Registration No. 333-98553 as Exhibit 10.15.)
(a)69 - Purchased Power Agreement between Georgia Power and LG&E Energy Marketing Inc. dated as of October 6, 1999. (Designated in Registration No. 333-98553 as Exhibit 10.16.)
(a)70 - Assignment and Assumption Agreement by and between Georgia Power and Southern Power dated as of July 31, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.17.)
(a)71 - Power Purchase Agreement between Southern Power and Alabama Power dated as of June 1, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.18.)
(a)72 - Amended and Restated Power Purchase Agreement between Southern Power and Georgia Power at Plant Autaugaville dated as of August 6, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.19.)
(a)73 - Contract for the Purchase of Firm Capacity and Energy between Southern Power and Savannah Electric dated as of July 26, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.20.)
(a)74 - Contract for the Purchase of Firm Capacity and Energy between Southern Power and Georgia Power dated as of July 26, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.21.)
(a)75 - Power Purchase Agreement between Southern Power and Georgia Power at Plant Goat Rock dated as of March 30, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.22.)
(a)76 - Power Purchase Agreement between Southern Company - Florida LLC and Kissimmee Utility Authority dated as of March 19, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.23.)
(a)77 - Power Purchase Agreement between Southern Company - Florida LLC and Florida Municipal Power Agency dated as of March 19, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.24.)
(a)78 - Power Purchase Agreement between Southern Company - Florida LLC and Orlando Utilities Commission dated as of March 19, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.25.)
E-17
(a)79 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 2002 and Amendments one through five thereto. (Designated in Southern Company's Form 10-K for the year ended December 31, 2001, File No. 1-3526, as Exhibit 10(a)52, in Registration No. 333-96883, as Exhibit 10.29 and in Southern Company's Form 10-Q for the quarter ended September 30, 2003, File No.1-3526, as Exhibit 10(a)1.)
(a)80 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 2002 and Amendments one through five thereto. (Designated in Southern Company's Form 10-K for the year ended December 31, 2001, File No. 1-3526, as Exhibit 10(a)53, in Southern Company's Form 10-K for the year ended December 31, 2002, File No. 1-3526, as Exhibit 10(a)81 and in Southern Company's Form 10-Q for the quarter ended September 30, 2003, File No. 1-3526, as Exhibit 10(a)2.)
# (a)81 - Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. (Designated in Form S-8, File No. 333-73462, as Exhibit 4(c).)
# (a)82 - The Deferred Compensation Plan for the Directors of The Southern Company, Amended and Restated effective February 19, 2001. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)59.)
# (a)83 - The Southern Company Outside Directors Pension Plan. (Designated in Southern Company's Form 10-K for the year ended December 31, 1994, File No. 1-3526, as Exhibit 10(a)77.)
# (a)84 - The Southern Company Deferred Compensation Plan, Amended and Restated effective February 23, 2001 and First Amendment thereto. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)61 and in Southern Company's Form 10-Q for the quarter ended September 30, 2003, File No. 1-3526, as Exhibit 10(a)4.)
# (a)85 - The Southern Company Outside Directors Stock Plan and First Amendment thereto. (Designated in Registration No. 33-54415 as Exhibit 4(c) and in Southern Company's Form 10-K for the year ended December 31, 1995, File No. 1-3526, as Exhibit 10(a)79.)
# (a)86 - Outside Directors Stock Plan for Subsidiaries of The Southern Company, Amended and Restated effective January 1, 2000. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)63.)
(a)87 - The Southern Company Pension Plan, Amended and Restated effective January 1, 2002 and First Amendment thereto. (Designated in Southern Company's Form 10-K for the year ended December 31, 2002, File No. 1-3526, as Exhibit 10(a)88 and in Southern Company's Form 10-Q for the quarter ended June 30, 2003, File No. 1-3526, as Exhibit 10(a)4.)
E-18
# (a)88 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. (Designated in Southern Company's Form 10-K for the year ended December 31, 2001, File No. 1-3526, as Exhibit 10(a)62.)
# (a)89 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)64 and in Southern Company's Form 10-Q for the quarter ended September 30, 2003, File No. 1-3526, as Exhibit 10(a)3.)
(a)90 - Southern Company Change in Control Severance Plan, Amended and Restated effective May 1, 2003. (Designated in Southern Company's Form 10-Q for the quarter ended June 30, 2003, File No. 1-3526, as Exhibit 10(a)1.)
# (a)91 - Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. (Designated in Southern Company's Form 10-Q for the quarter ended June 30, 2003, File No. 1-3526, as Exhibit 10(a)2.)
# (a)92 - Deferred Compensation Agreement between Southern Company, Southern Nuclear and William G. Hairston III. (Designated in Southern Company's Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)81.)
# (a)93 - Amended and Restated Change in Control Agreement between Southern Company, Mississippi Power and Dwight H. Evans. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)81.)
# (a)94 - Amended and Restated Change in Control Agreement between Southern Company, SCS and Henry Allen Franklin. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)83.)
# (a)95 - Amended and Restated Change in Control Agreement between Southern Company, Southern Nuclear and William G. Hairston, III. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)84.)
# (a)96 - Amended and Restated Change in Control Agreement between Southern Company, Savannah Electric and G. Edison Holland, Jr. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)86.)
# (a)97 - Amended and Restated Change in Control Agreement between Southern Company, SCS and C. Alan Martin. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)87.)
# (a)98 - Amended and Restated Change in Control Agreement between Southern Company, SCS and Charles Douglas McCrary. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)88.)
# (a)99 - Amended and Restated Change in Control Agreement between Southern Company, Georgia Power and David M. Ratcliffe. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)89.)
E-19
# (a)100 - Amended and Restated Change in Control Agreement between Southern Company, SCS and Stephen A. Wakefield. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)90.)
# (a)101 - Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. (Designated in Southern Company's Form 10-K for the year ended December 31, 2002, File No. 1-3526, as Exhibit 10(a)105.)
# (a)102 - Master Separation and Distribution Agreement dated as of September 1, 2000 between Southern Company and Mirant. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)100.)
# (a)103 - Indemnification and Insurance Matters Agreement dated as of September 1, 2000 between Southern Company and Mirant. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)101.)
# (a)104 - Tax Indemnification Agreement dated as of September 1, 2000 among Southern Company and its affiliated companies and Mirant and its affiliated companies. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)102.)
# (a)105 - Southern Company Deferred Compensation Trust Agreement as amended and restated effective January 1, 2001 between Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Communications, Energy Solutions and Southern Nuclear. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)103.)
# (a)106 - Deferred Stock Trust Agreement for Directors of Southern Company and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)104.)
# (a)107 - Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its subsidiaries, effective September 1, 2001, between Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. (Designated in Southern Company's Form 10-K for the year ended December 31, 2001, File No. 1-3526, as Exhibit 10(a)92.)
# (a)108 - Change in Control Agreement between Southern Company, Mississippi Power and Michael D. Garrett. (Designated in Southern Company's Form 10-K for the year ended December 31, 2002, File No. 1-3526, as Exhibit 10(a)112.)
# (a)109 - Change in Control Agreement between Southern Company, Savannah Electric and Anthony R. James. (Designated in Southern Company's Form 10-K for the year ended December 31, 2002, File No. 1-3526, as Exhibit 10(a)113.)
E-20
# (a)110 - Change in Control Agreement between Southern Company, SCS and W. Paul Bowers. (Designated in Southern Company's Form 10-K for the year ended December 31, 2002, File No. 1-3526, as Exhibit 10(a)114.)
# (a)111 - Change in Control Agreement between Southern Company, Gulf Power and Thomas A. Fanning. (Designated in Southern Company's Form 10-K for the year ended December 31, 2002, File No. 1-3526, as Exhibit 10(a)115.)
# (a)112 - Deferred Compensation Agreement between Southern Company, SCS and Christopher C. Womack dated May 31, 2002. (Designated in Southern Company's Form 10-K for the year ended December 31, 2002, File No. 1-3526, as Exhibit 10(a)118.)
# (a)113 - Supplemental Pension Agreement between Savannah Electric, Gulf Power, SCS and G. Edison Holland, Jr. effective February 22, 2002. (Designated in Southern Company's Form 10-K for the year ended December 31, 2002, File No. 1-3526, as Exhibit 10(a)119.)
# (a)114 - Amended and Restated Supplemental Pension Agreement between Georgia Power, Southern Company, SCS and C. B. Harreld dated September 17, 2003. (Designated in Southern Company's Form 10-Q for the quarter ended September 30, 2003, File No. 1-3526, as Exhibit 10(a)5.)
# (a)115 - Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. (Designated in Southern Company's Form 10-Q for the quarter ended June 30, 2003, File No. 1-3526, as Exhibit 10(a)3.)
Alabama Power
(b)1 - Service contracts dated as of January 1, 1984, between SCS and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, SEGCO and Southern Company and Amendment No. 1 dated as of September 6, 1985 between SCS and Southern Company. See Exhibit 10(a)1 herein.
(b)2 - Interchange contract dated February 17, 2000, between Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power and SCS. See Exhibit 10(a)6 herein.
(b)3 - Agreement dated as of January 27, 1959, Amendment No. 1 dated as of October 27, 1982 and Amendment No. 2 dated November 4, 1993 and effective June 1, 1994, among SEGCO, Alabama Power and Georgia Power. See Exhibit 10(a)7 herein.
(b)4 - Unit Power Sales Agreement dated July 19, 1988, between FPC and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. See Exhibit 10(a)33 herein.
(b)5 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. See Exhibit 10(a)34 herein.
E-21
(b)6 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. See Exhibit 10(a)35 herein.
(b)7 - 1991 Firm Power Purchase Contract between Alabama Power and AMEA. (Designated in Form U-1, File No. 70-7873, as Exhibit B-1.)
(b)8 - Purchase and Ownership Agreement for Joint Ownership Interest in the James H. Miller, Jr. Steam Electric Generating Plant Units One and Two dated November 18, 1988, between Alabama Power and AEC. See Exhibit 10(a)38 herein.
(b)9 - Operating Agreement for Joint Ownership Interest in the James H. Miller, Jr. Steam Electric Generating Plant Units One and Two dated November 18, 1988, between Alabama Power and AEC. See Exhibit 10(a)39 herein.
(b)10 - Long Term Transmission Service Agreement between Entergy Power, Inc. and Alabama Power, Mississippi Power and SCS. See Exhibit 10(a)47 herein.
(b)11 - Operating Agreement for the Joseph M. Farley Nuclear Plant between Alabama Power and Southern Nuclear dated as of December 23, 1991. See Exhibit 10(a)51 herein.
*(b)12 - Amended and Restated Operating Agreement between Southern Power and Alabama Power effective December 1, 2002. See Exhibit 10(a)59 herein.
(b)13 - Interconnection Agreement by and between Southern Power and Alabama Power for Autaugaville Combined Cycle Unit 1 dated as of June 25, 2001. See Exhibit 10(a)66 herein.
(b)14 - Interconnection Agreement by and between Southern Power and Alabama Power for Autaugaville Combined Cycle Unit 2 dated as of June 25, 2001. See Exhibit 10(a)67 herein.
(b)15 - Power Purchase Agreement between Southern Power and Alabama Power dated as of June 1, 2001. See Exhibit 10(a)71 herein.
(b)16 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 2002 and Amendments one through five thereto. See Exhibit 10(a)79 herein.
(b)17 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 2002 and Amendments one through five thereto. See Exhibit 10(a)80 herein.
# (b)18 - Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)81 herein.
# (b)19 - The Southern Company Deferred Compensation Plan, Amended and Restated effective February 23, 2001 and First Amendment thereto. See Exhibit 10(a)84 herein.
E-22
# (b)20 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)83 herein.
# (b)21 - Outside Directors Stock Plan for Subsidiaries of The Southern Company, Amended and Restated effective January 1, 2000. See Exhibit 10(a)86 herein.
(b)22 - The Southern Company Pension Plan, Amended and Restated effective January 1, 2002 and First Amendment thereto. See Exhibit 10(a)87 herein.
# (b)23 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)88 herein.
# (b)24 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)89 herein.
(b)25 - Southern Company Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)90 herein.
# (b)26 - Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)91 herein.
# (b)27 - Deferred Compensation Plan for Directors of Alabama Power Company, Amended and Restated effective January 1, 2001. (Designated in Alabama Power's Form 10-K for the year ended December 31, 2001, File No. 1-3164, as Exhibit 10(b)28.)
# (b)28 - Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)101 herein.
# (b)29 - Southern Company Deferred Compensation Trust Agreement as amended and restated effective January 1, 2001 between Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Communications, Energy Solutions and Southern Nuclear. See Exhibit 10(a)105 herein.
# (b)30 - Deferred Stock Trust Agreement for Directors of Southern Company and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)106 herein.
# (b)31 - Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its subsidiaries, effective September 1, 2001, between Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)107 herein.
# (b)32 - Deferred Compensation Agreement between Alabama Power and William B. Hutchins, III dated April 11, 2003. (Designated in Alabama Power's Form 10-Q for the quarter ended March 31, 2003, File No. 1-3164, as Exhibit 10(b)1.)
E-23
# (b)33 - Amended and Restated Supplemental Pension Agreement among SCS, Southern Nuclear, Alabama Power and James H. Miller, III. (Designated in Alabama Power's Form 10-Q for the quarter ended June 30, 2003, File No. 1-3164, as Exhibit 10(b)1.)
# (b)34 - Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)115 herein.
Georgia Power
(c)1 - Service contracts dated as of January 1, 1984, between SCS and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, SEGCO and Southern Company and Amendment No. 1 dated as of September 6, 1985, between SCS and Southern Company. See Exhibit 10(a)1 herein.
(c)2 - Interchange contract dated February 17, 2000, between Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power and SCS. See Exhibit 10(a)6 herein.
(c)3 - Agreement dated as of January 27, 1959, Amendment No. 1 dated as of October 27, 1982 and Amendment No. 2 dated November 4, 1993 and effective June 1, 1994, among SEGCO, Alabama Power and Georgia Power. See Exhibit 10(a)7 herein.
(c)4 - Joint Committee Agreement dated as of August 27, 1976, among Georgia Power, OPC, MEAG and Dalton. See Exhibit 10(a)8 herein.
(c)5 - Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation Agreement dated as of January 6, 1975, between Georgia Power and OPC. See Exhibit 10(a)9 herein.
(c)6 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as of January 6, 1975, between Georgia Power and OPC. See Exhibit 10(a)10 herein.
(c)7 - Revised and Restated Integrated Transmission System Agreement dated as of November 12, 1990, between Georgia Power and OPC. See Exhibit 10(a)11 herein.
(c)8 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of March 26, 1976, between Georgia Power and OPC. See Exhibit 10(a)12 herein.
(c)9 - Plant Hal Wansley Operating Agreement dated as of March 26, 1976, between Georgia Power and OPC. See Exhibit 10(a)13 herein.
(c)10 - Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation Agreement dated as of August 27, 1976, between Georgia Power, MEAG and Dalton. See Exhibit 10(a)14 herein.
(c)11 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as of August 27, 1976, between Georgia Power, MEAG and Dalton. See Exhibit 10(a)15 herein.
E-24
(c)12 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase and Ownership Participation Agreement dated as of August 27, 1976 and Amendment No. 1 dated as of January 18, 1977, among Georgia Power, OPC, MEAG and Dalton. See Exhibit 10(a)16 herein.
(c)13 - Alvin W. Vogtle Nuclear Units Number One and Two Operating Agreement dated as of August 27, 1976, among Georgia Power, OPC, MEAG and Dalton. See Exhibit 10(a)17 herein.
(c)14 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase, Amendment, Assignment and Assumption Agreement dated as of November 16, 1983, between Georgia Power and MEAG. See Exhibit 10(a)18 herein.
(c)15 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of August 27, 1976, between Georgia Power and MEAG. See Exhibit 10(a)19 herein.
(c)16 - Plant Hal Wansley Operating Agreement dated as of August 27, 1976, between Georgia Power and MEAG. See Exhibit 10(a)20 herein.
(c)17 - Nuclear Operating Agreement between Southern Nuclear and Georgia Power dated as of July 1, 1993. See Exhibit 10(a)21 herein.
(c)18 - Pseudo Scheduling and Services Agreement between Georgia Power and MEAG dated as of April 8, 1997. See Exhibit 10(a)22 herein.
(c)19 - Plant Hal Wansley Purchase and Ownership Participation Agreement dated as of April 19, 1977, between Georgia Power and Dalton. See Exhibit 10(a)23 herein.
(c)20 - Plant Hal Wansley Operating Agreement dated as of April 19, 1977, between Georgia Power and Dalton. See Exhibit 10(a)24 herein.
(c)21 - Plant Robert W. Scherer Units Number One and Two Purchase and Ownership Participation Agreement dated as of May 15, 1980, Amendment No. 1 dated as of December 30, 1985, Amendment No. 2 dated as of July 1, 1986, Amendment No. 3 dated as of August 1, 1988 and Amendment No. 4 dated as of December 31, 1990, among Georgia Power, OPC, MEAG and Dalton. See Exhibit 10(a)25 herein.
(c)22 - Plant Robert W. Scherer Units Number One and Two Operating Agreement dated as of May 15, 1980, Amendment No. 1 dated as of December 3, 1985 and Amendment No. 2 dated as of December 31, 1990, among Georgia Power, OPC, MEAG and Dalton. See Exhibit 10(a)26 herein.
(c)23 - Plant Robert W. Scherer Purchase, Sale and Option Agreement dated as of May 15, 1980, between Georgia Power and MEAG. See Exhibit 10(a)27 herein.
(c)24 - Plant Robert W. Scherer Purchase and Sale Agreement dated as of May 16, 1980, between Georgia Power and Dalton. See Exhibit 10(a)28 herein.
(c)25 - Plant Robert W. Scherer Unit Number Three Purchase and Ownership Participation Agreement dated as of March 1, 1984, Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2 dated as of August 1, 1988, between Georgia Power and Gulf Power. See Exhibit 10(a)29 herein.
E-25
(c)26 - Plant Robert W. Scherer Unit Number Three Operating Agreement dated as of March 1, 1984, between Georgia Power and Gulf Power. See Exhibit 10(a)30 herein.
(c)27 - Plant Robert W. Scherer Unit No. Four Amended and Restated Purchase and Ownership Participation Agreement by and among Georgia Power, FP&L and JEA dated as of December 31, 1990 and Amendment No. 1 dated as of June 15, 1994. See Exhibit 10(a)31 herein.
(c)28 - Plant Robert W. Scherer Unit No. Four Operating Agreement by and among Georgia Power, FP&L and JEA dated as of December 31, 1990 and Amendment No. 1 dated as of June 15, 1994. See Exhibit 10(a)32 herein.
(c)29 - Unit Power Sales Agreement dated July 19, 1988, between FPC and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. See Exhibit 10(a)33 herein.
(c)30 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. See Exhibit 10(a)34 herein.
(c)31 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. See Exhibit 10(a)35 herein.
(c)32 - Rocky Mountain Pumped Storage Hydroelectric Project Ownership Participation Agreement dated November 18, 1988, between OPC and Georgia Power. See Exhibit 10(a)36 herein.
(c)33 - Rocky Mountain Pumped Storage Hydroelectric Project Operating Agreement dated November 18, 1988, between OPC and Georgia Power. See Exhibit 10(a)37 herein.
(c)34 - Long Term Transaction Service Agreement between Georgia Power and OPC dated as of February 26, 1999. See Exhibit 10(a)41 herein.
(c)35 - Revised and Restated Coordination Services Agreement between and among Georgia Power, OPC and Georgia Systems Operations Corporation dated as of September 10, 1997. See Exhibit 10(a)42 herein.
(c)36 - Amended and Restated Nuclear Managing Board Agreement for Plant Hatch and Plant Vogtle among Georgia Power, OPC, MEAG and Dalton dated as of July 1, 1993. See Exhibit 10(a)43 herein.
(c)37 - Integrated Transmission System Agreement, Power Sale and Coordination Umbrella Agreement between Georgia Power and OPC dated as of November 12, 1990. See Exhibit 10(a)44 herein.
(c)38 - Revised and Restated Integrated Transmission System Agreement between Georgia Power and Dalton dated as of December 7, 1990. See Exhibit 10(a)45 herein.
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(c)39 - Revised and Restated Integrated Transmission System Agreement between Georgia Power and MEAG dated as of December 7, 1990. See Exhibit 10(a)46 herein.
(c)40 - Plant Scherer Managing Board Agreement dated as of December 31, 1990 among Georgia Power, OPC, MEAG, Dalton, Gulf Power, FP&L and JEA. See Exhibit 10(a)48 herein.
(c)41 - Plant McIntosh Combustion Turbine Purchase and Ownership Participation Agreement between Georgia Power and Savannah Electric dated as of December 15, 1992. See Exhibit 10(a)49 herein.
(c)42 - Plant McIntosh Combustion Turbine Operating Agreement between Georgia Power and Savannah Electric dated as of December 15, 1992. See Exhibit 10(a)50 herein.
*(c)43 - Amended and Restated Operating Agreement between Southern Power and Georgia Power dated effective December 1, 2002. See Exhibit 10(a)60 herein.
(c)44 - Interconnection Agreement by and between Southern Power and Georgia Power for Plant Dahlberg dated as of July 31, 2001. See Exhibit 10(a)62 herein.
(c)45 - Interconnection Agreement by and between Southern Power and Georgia Power for Wansley CC Units 6 and 7 dated as of May 10, 2001. See Exhibit 10(a)63 herein.
(c)46 - Interconnection Agreement by and between Southern Power and Georgia Power for Goat Rock CC Unit 1 dated as of May 10, 2001. See Exhibit 10(a)64 herein.
(c)47 - Revised and Restated Interconnection Agreement by and between Southern Power and Georgia Power for Goat Rock CC Unit 2 dated as of October 18, 2001. See Exhibit 10(a)65 herein.
(c)48 - Purchased Power Agreement between Georgia Power and LG&E Energy Marketing Inc. dated as of November 24, 1998. See Exhibit 10(a)68 herein.
(c)49 - Purchased Power Agreement between Georgia Power and LG&E Energy Marketing Inc. dated as of October 6, 1999. See Exhibit 10(a)69 herein.
(c)50 - Assignment and Assumption Agreement by and between Georgia Power and Southern Power dated as of July 31, 2001. See Exhibit 10(a)70 herein.
(c)51 - Amended and Restated Power Purchase Agreement between Southern Power and Georgia Power at Plant Autaugaville dated as of August 6, 2001. See Exhibit 10(a)72 herein.
(c)52 - Contract for the Purchase of Firm Capacity and Energy between Southern Power and Georgia Power dated as of July 26, 2001. See Exhibit 10(a)74 herein.
(c)53 - Power Purchase Agreement between Southern Power and Georgia Power at Plant Goat Rock dated as of March 30, 2001. See Exhibit 10(a)75 herein.
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(c)54 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 2002 and Amendments one through five thereto. See Exhibit 10(a)79 herein.
(c)55 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 2002 and Amendments one through five thereto. See Exhibit 10(a)80 herein.
# (c)56 - Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)81 herein.
# (c)57 - The Southern Company Deferred Compensation Plan, Amended and Restated effective February 23, 2001 and First Amendment thereto. See Exhibit 10(a)84 herein.
# (c)58 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)83 herein.
# (c)59 - Outside Directors Stock Plan for Subsidiaries of The Southern Company, Amended and Restated effective January 1, 2000. See Exhibit 10(a)86 herein.
(c)60 - The Southern Company Pension Plan, Amended and Restated effective January 1, 2002 and First Amendment thereto. See Exhibit 10(a)87 herein.
# (c)61 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)88 herein.
# (c)62 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)89 herein.
(c)63 - Southern Company Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)90 herein.
# (c)64 - Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)91 herein.
# (c)65 - Amended and Restated Change in Control Agreement between Southern Company, Georgia Power and David M. Ratcliffe. See Exhibit 10(a)99 herein.
# (c)66 - Deferred Compensation Plan For Directors of Georgia Power Company, Amended and Restated Effective January 13, 2003. (Designated in Georgia Power's Form 10-K for the year ended December 31, 2002, File No. 1.6468, as Exhibit 10(c)68.)
# (c)67 - Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)101 herein.
# (c)68 - Southern Company Deferred Compensation Trust Agreement as amended and restated effective January 1, 2001 between Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Communications, Energy Solutions and Southern Nuclear. See Exhibit 10(a)105 herein.
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# (c)69 - Deferred Stock Trust Agreement for Directors of Southern Company and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)106 herein.
# (c)70 - Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its subsidiaries, effective September 1, 2001, between Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)107 herein.
# (c)71 - Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)115 herein.
Gulf Power
(d)1 - Service contracts dated as of January 1, 1984, between SCS and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, SEGCO and Southern Company and Amendment No. 1 dated as of September 6, 1985, between SCS and Southern Company. See Exhibit 10(a)1 herein.
(d)2 - Interchange contract dated February 17, 2000, between Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power and SCS. See Exhibit 10(a)6 herein.
(d)3 - Plant Robert W. Scherer Unit Number Three Purchase and Ownership Participation Agreement dated as of March 1, 1984, Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2 dated as of August 1, 1988, between Georgia Power and Gulf Power. See Exhibit 10(a)29 herein.
(d)4 - Plant Robert W. Scherer Unit Number Three Operating Agreement dated as of March 1, 1984, between Georgia Power and Gulf Power. See Exhibit 10(a)30 herein.
(d)5 - Plant Scherer Managing Board Agreement dated as of December 31, 1990 among Georgia Power, OPC, MEAG, Dalton, Gulf Power, FP&L and JEA. See Exhibit 10(a)48 herein.
(d)6 - Unit Power Sales Agreement dated July 19, 1988, between FPC and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. See Exhibit 10(a)33 herein.
(d)7 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. See Exhibit 10(a)34 herein.
(d)8 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. See Exhibit 10(a)35 herein.
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(d)9 - Agreement between Gulf Power and AEC, effective August 1, 1985. (Designated in Gulf Power's Form 10-K for the year ended December 31, 1985, File No. 0-2429, as Exhibit 10(g).)
(d)10 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 2002 and Amendments one through five thereto. See Exhibit 10(a)79 herein.
(d)11 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 2002 and Amendments one through five thereto. See Exhibit 10(a)80 herein.
# (d)12 - Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)81 herein.
# (d)13 - The Southern Company Deferred Compensation Plan, Amended and Restated effective February 23, 2001 and First Amendment thereto. See Exhibit 10(a)84 herein.
# (d)14 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)83 herein.
# (d)15 - Outside Directors Stock Plan for Subsidiaries of The Southern Company, Amended and Restated effective January 1, 2000. See Exhibit 10(a)86 herein.
(d)16 - The Southern Company Pension Plan, Amended and Restated effective January 1, 2002 and First Amendment thereto. See Exhibit 10(a)87 herein.
# (d)17 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)89 herein.
(d)18 - Southern Company Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)90 herein.
# (d)19 - Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)91 herein.
# (d)20 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)88 herein.
# (d)21 - Supplemental Pension Agreement between Savannah Electric, Gulf Power, SCS and G. Edison Holland, Jr. effective February 22, 2002. See Exhibit 10(a)113 herein.
# (d)22 - Deferred Compensation Plan For Directors of Gulf Power Company, Amended and Restated Effective January 1, 2000 and First Amendment thereto. (Designated in Gulf Power's Form 10-K for the year ended December 31, 2000, File No. 0-2429 as Exhibit 10(d)33.)
# (d)23 - Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)101 herein.
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# (d)24 - Southern Company Deferred Compensation Trust Agreement as amended and restated effective January 1, 2001 between Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Communications, Energy Solutions and Southern Nuclear. See Exhibit 10(a)105 herein.
# (d)25 - Deferred Stock Trust Agreement for Directors of Southern Company and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)106 herein.
# (d)26 - Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its subsidiaries, effective September 1, 2001, between Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)107 herein.
# (d)27 - Change in Control Agreement between Southern Company, Gulf Power and Thomas A. Fanning. See Exhibit 10(a)111 herein.
# (d)28 - Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)115 herein.
Mississippi Power
(e)1 - Service contracts dated as of January 1, 1984, between SCS and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, SEGCO and Southern Company and Amendment No. 1 dated as of September 6, 1985, between SCS and Southern Company. See Exhibit 10(a)1 herein.
(e)2 - Interchange contract dated February 17, 2000, between Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power and SCS. See Exhibit 10(a)6 herein.
(e)3 - Unit Power Sales Agreement dated July 19, 1988, between FPC and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. See Exhibit 10(a)33 herein.
(e)4 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. See Exhibit 10(a)34 herein.
(e)5 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. See Exhibit 10(a)35 herein.
(e)6 - Transmission Facilities Agreement dated February 25, 1982, Amendment No. 1 dated May 12, 1982 and Amendment No. 2 dated December 6, 1983, between Entergy Corporation (formerly Gulf States) and Mississippi Power. See Exhibit 10(a)40 herein.
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(e)7 - Long Term Transmission Service Agreement between Entergy Power, Inc. and Alabama Power, Mississippi Power and SCS. See Exhibit 10(a)47 herein.
(e)8 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 2002 and Amendments one through five thereto. See Exhibit 10(a)79 herein.
(e)9 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 2002 and Amendments one through five thereto. See Exhibit 10(a)80 herein.
# (e)10 - Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)81 herein.
# (e)11 - The Southern Company Deferred Compensation Plan, Amended and Restated effective February 23, 2001 and First Amendment thereto. See Exhibit 10(a)84 herein.
# (e)12 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)83 herein.
# (e)13 - Outside Directors Stock Plan for Subsidiaries of The Southern Company, Amended and Restated effective January 1, 2000. See Exhibit 10(a)86 herein.
(e)14 - The Southern Company Pension Plan, Amended and Restated effective January 1, 2002 and First Amendment thereto. See Exhibit 10(a)87 herein.
# (e)15 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)89 herein.
(e)16 - Southern Company Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)90 herein.
# (e)17 - Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)91 herein.
# (e)18 - Amended and Restated Change in Control Agreement between Southern Company, Mississippi Power and Dwight H. Evans. See Exhibit 10(a)93 herein.
# (e)19 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)88 herein.
# (e)20 - Deferred Compensation Plan for Directors of Mississippi Power Company, Amended and Restated Effective January 1, 2000 and Amendment Number One thereto. (Designated in Mississippi Power's Form 10-K for the year ended December 31, 1999, File No. 0-6849 as Exhibit 10(e)37 and in Mississippi Power's Form 10-K for the year December 31, 2000, File No. 0-6849 as Exhibit 10(e)30.)
# (e)21 - Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)101 herein.
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# (e)22 - Southern Company Deferred Compensation Trust Agreement as amended and restated effective January 1, 2001 between Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Communications, Energy Solutions and Southern Nuclear. See Exhibit 10(a)105 herein.
# (e)23 - Deferred Stock Trust Agreement for Directors of Southern Company and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)106 herein.
# (e)24 - Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its subsidiaries, effective September 1, 2001, between Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)107 herein.
# (e)25 - Change in Control Agreement between Southern Company, Mississippi Power and Michael D. Garrett. See Exhibit 10(a)108 herein.
# (e)26 - Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)115 herein.
#*(e)27 - Separation Agreement between Henry E. Blakeslee and Mississippi Power effective January 1, 2004.
#*(e)28 - Consulting Agreement between Henry E. Blakeslee and Mississippi Power effective January 1, 2004.
Savannah Electric
(f)1 - Service contract dated as of March 3, 1988, between SCS and Savannah Electric. See Exhibit 10(a)3 herein.
(f)2 - Interchange contract dated February 17, 2000, between Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power and SCS. See Exhibit 10(a)6 herein.
(f)3 - Unit Power Sales Agreement dated July 19, 1988, between FPC and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. See Exhibit 10(a)33 herein.
(f)4 - Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. See Exhibit 10(a)34 herein.
(f)5 - Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. See Exhibit 10(a)35 herein.
E-33
(f)6 - Plant McIntosh Combustion Turbine Purchase and Ownership Participation Agreement between Georgia Power and Savannah Electric dated as of December 15, 1992. See Exhibit 10(a)49 herein.
(f)7 - Plant McIntosh Combustion Turbine Operating Agreement between Georgia Power and Savannah Electric dated December 15, 1992. See Exhibit 10(a)50 herein.
(f)8 - Contract for the Purchase of Firm Capacity and Energy between Southern Power and Savannah Electric dated as of July 26, 2001. See Exhibit 10(a)73 herein.
(f)9 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 2002 and Amendments one through five thereto. See Exhibit 10(a)79 herein.
(f)10 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 2002 and Amendments one through five thereto. See Exhibit 10(a)80 herein.
# (f)11 - Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)81 herein.
# (f)12 - Supplemental Executive Retirement Plan of Savannah Electric, Amended and Restated effective October 26, 2000. (Designated in Savannah Electric's Form 10-K for the year ended December 31, 2000, File No. 1-5072 as Exhibit 10(f)13.)
# (f)13 - Deferred Compensation Plan for Key Employees of Savannah Electric, Amended and Restated effective October 26, 2000. (Designated in Savannah Electric's Form 10-K for the year ended December 31, 2000, File No. 1-5072 as Exhibit 10(f)14.)
# (f)14 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)83 herein.
# (f)15 - Deferred Compensation Plan for Directors of Savannah Electric, Amended and Restated effective October 26, 2000. (Designated in Savannah Electric's Form 10-K for the year ended December 31, 2000, File No. 1-5072 as Exhibit 10(f)18.)
# (f)16 - Outside Directors Stock Plan for Subsidiaries of The Southern Company, Amended and Restated effective January 1, 2000. See Exhibit 10(a)86 herein.
(f)17 - The Southern Company Pension Plan, Amended and Restated effective January 1, 2002 and First Amendment thereto. See Exhibit 10(a)87 herein.
# (f)18 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)89 herein.
(f)19 - Southern Company Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)90 herein.
# (f)20 - Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)91 herein.
E-34
# (f)21 - Amended and Restated Change in Control Agreement between Southern Company, Savannah Electric and G. Edison Holland, Jr. See Exhibit 10(a)96 herein.
# (f)22 - The Southern Company Deferred Compensation Plan, Amended and Restated effective February 23, 2001 and First Amendment thereto. See Exhibit 10(a)84 herein.
# (f)23 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)88 herein.
# (f)24 - Supplemental Pension Agreement between Savannah Electric, Gulf Power, SCS and G. Edison Holland, Jr. effective February 22, 2002. See Exhibit 10(a)113 herein.
# (f)25 - Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)101 herein.
# (f)26 - Agreement for supplemental pension benefits between Savannah Electric and William Miles Greer. (Designated in Savannah Electric's Form 10-K for the year ended December 31, 2000, File No. 1-5072 as Exhibit 10(f)34.)
# (f)27 - Agreement crediting additional service between Savannah Electric and William Miles Greer. (Designated in Savannah Electric's Form 10-K for the year ended December 31, 2000, File No. 1-5072 as Exhibit 10(f)35.)
# (f)28 - Southern Company Deferred Compensation Trust Agreement as amended and restated effective January 1, 2001 between Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Communications, Energy Solutions and Southern Nuclear. See Exhibit 10(a)105 herein.
# (f)29 - Deferred Stock Trust Agreement for Directors of Southern Company and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)106 herein.
# (f)30 - Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its subsidiaries, effective September 1, 2001, between Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)107 herein.
# (f)31 - Change in Control Agreement between Southern Company, Savannah Electric and Anthony R. James. See Exhibit 10(a)109 herein.
# (f)32 - Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)115 herein.
*(f)33 - Operating Agreement between Southern Power and Savannah Electric effective January 1, 2003. See Exhibit 10(a)61 herein.
E-35
#*(f)34 - Savannah Electric and Power Company Change in Control Plan Benefit Determination Policy, effective October 26, 2000.
Southern Power
(g)1 - Service contract dated as of January 1, 2001, between SCS and Southern Power. See Exhibit 10(a)2 herein.
(g)2 - Interchange contract dated February 17, 2000, between Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power and SCS. See Exhibit 10(a)6 herein.
(g)3 - Amended and Restated Credit Agreement among Southern Power, Citibank N.A., as the administrative agent, and the lenders listed therein dated as of April 17, 2003. See Exhibit 10(a)52 herein.
(g)4 - Completion Guarantee among Southern Company, Southern Power and Citibank, N.A., in its capacity as agent for the Lenders under the Credit Facility dated as of November 15, 2001. See Exhibit 10(a)53 herein.
(g)5 - Letter Amendment No. 1 to Completion Guarantee among Southern Company, Southern Power and Citibank, N.A. in its capacity as agent for the Lenders under the Credit Facility dated as of April 17, 2003. See Exhibit 10(a)55 herein.
(g)6 - Completion Guarantee Supplement by Southern Company and Southern Power dated as of April 22, 2002. See Exhibit 10(a)54 herein.
(g)7 - Equity Contribution Agreement among Southern Company and Citibank, N.A. in its capacity as agent for the Lenders under the Credit Facility dated as of November 15, 2001. See Exhibit 10(a)56 herein.
(g)8 - Letter Amendment No. 1 to Equity Contribution Agreement among Southern Company, Southern Power and Citibank, N.A. in its capacity as agent for the Lenders under the Credit Facility dated as of April 17, 2003. See Exhibit 10(a)57 herein.
(g)9 - Equity Contribution Agreement Supplement by Southern Company and Southern Power dated as of April 22, 2002. See Exhibit 10(a)58 herein.
*(g)10 - Amended and Restated Operating Agreement between Southern Power and Alabama Power effective December 1, 2002. See Exhibit 10(a)59 herein.
*(g)11 - Amended and Restated Operating Agreement between Southern Power and Georgia Power effective December 1, 2002. See Exhibit 10(a)60 herein.
*(g)12 - Operating Agreement between Southern Power and Savannah Electric effective January 1, 2003. See Exhibit 10(a)61 herein.
(g)13 - Interconnection Agreement by and between Southern Power and Georgia Power for Plant Dahlberg dated as of July 31, 2001. See Exhibit 10(a)62 herein.
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(g)14 - Interconnection Agreement by and between Southern Power and Georgia Power for Wansley CC Units 6 and 7 dated as of May 10, 2001. See Exhibit 10(a)63 herein.
(g)15 - Interconnection Agreement by and between Southern Power and Georgia Power for Goat Rock CC Unit 1 dated as of May 10, 2001. See Exhibit 10(a)64 herein.
(g)16 - Revised and Restated Interconnection Agreement by and between Southern Power and Georgia Power for Goat Rock CC Unit 2 dated as of October 18, 2001. See Exhibit 10(a)65 herein.
(g)17 - Interconnection Agreement by and between Southern Power and Alabama Power for Autaugaville Combined Cycle Unit 1 dated as of June 25, 2001. See Exhibit 10(a)66 herein.
(g)18 - Interconnection Agreement by and between Southern Power and Alabama Power for Autaugaville Combined Cycle Unit 2 dated as of June 25, 2001. See Exhibit 10(a)67 herein.
(g)19 - Purchased Power Agreement between Georgia Power and LG&E Energy Marketing Inc. dated as of November 24, 1998. See Exhibit 10(a)68 herein.
(g)20 - Purchased Power Agreement between Georgia Power and LG&E Energy Marketing Inc. dated as of October 6, 1999. See Exhibit 10(a)69 herein.
(g)21 - Assignment and Assumption Agreement by and between Georgia Power and Southern Power dated as of July 31, 2001. See Exhibit 10(a)70 herein.
(g)22 - Power Purchase Agreement between Southern Power and Alabama Power dated as of June 1, 2001. See Exhibit 10(a)71 herein.
(g)23 - Amended and Restated Power Purchase Agreement between Southern Power and Georgia Power at Plant Autaugaville dated as of August 6, 2001. See Exhibit 10(a)72 herein.
(g)24 - Contract for the Purchase of Firm Capacity and Energy between Southern Power and Savannah Electric dated as of July 26, 2001. See Exhibit 10(a)73 herein.
(g)25 - Contract for the Purchase of Firm Capacity and Energy between Southern Power and Georgia Power dated as of July 26, 2001. See Exhibit 10(a)74 herein.
(g)26 - Power Purchase Agreement between Southern Power and Georgia Power at Plant Goat Rock dated as of March 30, 2001. See Exhibit 10(a)75 herein.
(g)27 - Power Purchase Agreement between Southern Company - Florida LLC and Kissimmee Utility Authority dated as of March 19, 2001. See Exhibit 10(a)76 herein.
(g)28 - Power Purchase Agreement between Southern Company - Florida LLC and Florida Municipal Power Agency dated as of March 19, 2001. See Exhibit 10(a)77 herein.
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(g)29 - Power Purchase Agreement between Southern Company - Florida LLC and Orlando Utilities Commission dated as of March 19, 2001. See Exhibit 10(a)78 herein.
(14) Code of Ethics
Southern Company
*(a) - The Southern Company Code of Ethics.
Alabama Power
*(b) - The Southern Company Code of Ethics. See Exhibit 14(a) herein.
Georgia Power
*(c) - The Southern Company Code of Ethics. See Exhibit 14(a) herein.
Gulf Power
*(d) - The Southern Company Code of Ethics. See Exhibit 14(a) herein.
Mississippi Power
*(e) - The Southern Company Code of Ethics. See Exhibit 14(a) herein.
Savannah Electric
*(f) - The Southern Company Code of Ethics. See Exhibit 14(a) herein.
Southern Power
*(g) - The Southern Company Code of Ethics. See Exhibit 14(a) herein.
(21) Subsidiaries of Registrants
Southern Company
*(a) - Subsidiaries of Registrant.
Alabama Power
*(b) - Subsidiaries of Registrant. See Exhibit 21(a) herein.
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Georgia Power
*(c) - Subsidiaries of Registrant. See Exhibit 21(a) herein.
Gulf Power
*(d) - Subsidiaries of Registrant. See Exhibit 21(a) herein.
Mississippi Power
*(e) - Subsidiaries of Registrant. See Exhibit 21(a) herein.
Savannah Electric
*(f) - Subsidiaries of Registrant. See Exhibit 21(a) herein.
Southern Power
*(g) - Subsidiaries of Registrant. See Exhibit 21(a) herein.
(23) Consents of Experts and Counsel
Southern Company
*(a)1 - Consent of Deloitte & Touche LLP.
*(a)2 - Notice Regarding Consent of Arthur Andersen LLP.
Alabama Power
*(b)1 - Consent of Deloitte & Touche LLP.
*(b)2 - Notice Regarding Consent of Arthur Andersen LLP. See Exhibit 23(a)2 herein.
Georgia Power
*(c)1 - Consent of Deloitte & Touche LLP.
*(c)2 - Notice Regarding Consent of Arthur Andersen LLP. See Exhibit 23(a)2 herein.
Gulf Power
*(d)1 - Consent of Deloitte & Touche LLP.
*(d)2 - Notice Regarding Consent of Arthur Andersen LLP. See Exhibit 23(a)2 herein.
Mississippi Power
*(e)1 - Consent of Deloitte & Touche LLP.
*(e)2 - Notice Regarding Consent of Arthur Andersen LLP. See Exhibit 23(a)2 herein.
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Savannah Electric
*(f)1 - Consent of Deloitte & Touche LLP.
*(f)2 - Notice Regarding Consent of Arthur Andersen LLP. See Exhibit 23(a)2 herein.
(24) Powers of Attorney and Resolutions
Southern Company
*(a) - Power of Attorney and resolution.
Alabama Power
*(b) - Power of Attorney and resolution.
Georgia Power
*(c) - Power of Attorney and resolution.
Gulf Power
*(d) - Power of Attorney and resolution.
Mississippi Power
*(e) - Power of Attorney and resolution.
Savannah Electric
*(f) - Power of Attorney and resolution.
Southern Power
*(g) - Power of Attorney and resolution.
(31) Section 302 Certifications
Southern Company
*(a)1 - Certificate of Southern Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*(a)2 - Certificate of Southern Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
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Alabama Power
*(b)1 - Certificate of Alabama Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*(b)2 - Certificate of Alabama Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Georgia Power
*(c)1 - Certificate of Georgia Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*(c)2 - Certificate of Georgia Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Gulf Power
*(d)1 - Certificate of Gulf Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*(d)2 - Certificate of Gulf Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Mississippi Power
*(e)1 - Certificate of Mississippi Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*(e)2 - Certificate of Mississippi Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Savannah Electric
*(f)1 - Certificate of Savannah Electric's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*(f)2 - Certificate of Savannah Electric's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Southern Power
*(g)1 - Certificate of Southern Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*(g)2 - Certificate of Southern Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
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(32) Section 906 Certifications
Southern Company
*(a) - Certificate of Southern Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
Alabama Power
*(b) - Certificate of Alabama Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
Georgia Power
*(c) - Certificate of Georgia Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
Gulf Power
*(d) - Certificate of Gulf Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
Mississippi Power
*(e) - Certificate of Mississippi Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
Savannah Electric
*(f) - Certificate of Savannah Electric's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
Southern Power
*(g) - Certificate of Southern Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
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