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 operating companies supply electric service in the states of Alabama, Georgia, Florida, Mississippi and Georgia, respectively. More particular information relating to each of the 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 is the primary growth engine for Southern Company's competitive wholesale market-based energy business. Southern Power is a corporation which was 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 Management Development, Southern Telecom, Southern Company Holdings and other direct and indirect subsidiaries. Southern LINC provides digital wireless communications services to Southern Company's 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 Management Development focuses on new and existing programs to enhance customer satisfaction, efficiency and stockholder value. Southern Telecom provides wholesale fiber optic solutions to telecommunication providers in the Southeastern United States. Southern Company Holdings is an intermediate holding subsidiary for Southern Company's investments in leveraged leases, alternative 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
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Gaston to the Georgia state line at which point connection is made with the Georgia Power transmission line system.
Reference is made to Note 12 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
Operating Companies
The transmission facilities of each of the 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 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 Operating Companies" 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 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 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 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 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 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 the operating companies and Southern Power.
SCS has contracted with Southern Company, each operating company, Southern Power, various of the other subsidiaries, Southern Nuclear and SEGCO 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 Management Development, Southern Company GAS, Southern LINC and Southern Telecom have also secured from the operating companies certain services which are furnished at cost.
Southern Nuclear has contracts with Alabama Power to operate the Farley Nuclear Plant 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 that is the primary growth engine for Southern Company's competitive wholesale market-based energy business. Southern Power constructs, acquires and owns generating facilities and sells the output under long-term, fixed-price capacity contracts both to unaffiliated wholesale purchasers as well as the operating companies (under PPAs approved by the respective PSCs). Southern Power's wholesale
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generating assets are not placed in the operating companies' rate bases, and Southern Power is only able to recover costs based on the terms of its PPAs. 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 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. Southern Power is a party to the intra-system interchange agreement and shares in the benefits and burdens of such arrangement. By the end of 2005, Southern Power plans to have approximately 6,600 megawatts of available generating capacity in commercial operation. At December 31, 2002, Southern Power had 2,400 megawatts of generating capacity in commercial operation.
Other Business
On June 3, 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. On July 19, 2002, Southern Company GAS completed its acquisition out of bankruptcy from The New Power Company (New Power) of approximately 210,000 retail natural gas customers located in the State of Georgia, representing a 15% market share. Southern Company GAS also purchased from New Power proprietary risk management software and hardware systems, natural gas inventory and accounts receivable. The total purchase price was approximately $60 million.
In 2001, Energy Solutions changed its name to Southern Management Development. Southern Management Development then created a separate entity, Southern Company Energy Solutions LLC (SCES LLC), for its energy services business which was contributed to Southern Company Holdings. SCES LLC provides energy related services and products. Southern Management Development focuses on new and existing programs to enhance customer satisfaction, efficiency and stockholder value.
Southern Company Holdings is an intermediate holding subsidiary for Southern Company's investments in leveraged leases and alternative fuel products, in addition to SCES LLC.
In 1996, Southern LINC began serving Southern Company's 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 August 2000, MESH filed a proposed plan of reorganization with the U.S. Bankruptcy Court. The proposed plan of reorganization was most recently amended on December 13, 2001. Southern Company expects that approval of a plan of reorganization would result in termination of Southern Company's ownership interest in MESH but would not affect Southern Company's continuing guarantee obligations. 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 "Mobile Energy Services' Petition for Bankruptcy" herein for additional information relating to this matter.
Mirant Corporation
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 within 12 months of the initial stock offering. On October 2, 2000, Mirant completed its initial public offering of 66.7 million shares of common stock priced at $22 per share. This represented 19.7 percent of the 338.7 million shares outstanding.
On February 19, 2001, Southern Company's board of directors approved the spin off of its remaining ownership of 272 million Mirant shares. On April 2, 2001, the tax-free distribution of Mirant shares was completed at a ratio of approximately 0.4 shares for every share of Southern Company common stock held on the record date.
As a result of the spin off, Southern Company's financial statements reflect Mirant's results of operations, balance sheets and cash flows as discontinued operations.
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Southern Company is involved in various matters being litigated. Reference is made to Item 3 - "Legal Proceedings" and to Note 3 to the financial statements of Southern Company in Item 8 herein for information regarding material issues that could possibly affect future earnings.
Risk Factors
In addition to the other information in this Form 10-K, the following factors should be 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, hydroelectric and nuclear generating facilities. For example, the rates charged to wholesale customers by the operating companies and by Southern Power must be approved by the FERC. In addition, the respective state PSCs must approve the 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 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 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
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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 and investigations by governmental authorities into energy trading activities, companies generally in the regulated and unregulated utility businesses have been under an increased amount of public and regulatory scrutiny. 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.
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 operating companies. Increased competition could result in increased pressure to lower the cost of electricity. Any adoption in the territories served by the operating companies of retail competition and the unbundling of regulated energy service could have a significant adverse financial impact on Southern Company and its subsidiaries due to an impairment of assets, a loss of retail customers, lower profit margins 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. 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.
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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 Phase I and Phase II of Title IV of the Clean Air Act totaled approximately $400 million. Construction expenditures for compliance with one-hour ozone non-attainment standards in Atlanta and Birmingham are expected to total approximately $980 million when completed in 2003.
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 additional 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.
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.
Southern Company's financial performance may be adversely affected if its subsidiaries are unable to successfully operate their electric generating facilities.
Southern Company's financial performance depends on the successful operation of its subsidiaries' electric generating facilities. Operating electric generating 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 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.
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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.
As of December 31, 2002, 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 10.1% of Southern Company's generation capacity. 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 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 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 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; o liquidity in the general wholesale electricity market; o weather conditions impacting demand for electricity;
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o seasonality; o transmission or transportation constraints or inefficiencies; o availability of competitively priced alternative energy sources; 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 operating companies, such increases may not be fully recoverable through rates. Other of these factors could reduce Southern Company's revenues.
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 operating companies to pass all of these purchase or construction costs on to their customers, the operating companies may not 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 operating companies' recovery in customers' rates. Under Southern Power's long-term, fixed price PPAs, it 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 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;
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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 have been disrupted in general. Additionally, the bankruptcy of Enron Corporation and events related to the California electric market crisis have both limited the availability and increased the cost of capital for Southern Company's businesses and that of Southern Company's competitors. 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. The continuation of the current economic downturn and disruption of financial markets could also 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 additions or acquisitions of property during 2003 through 2005 by the operating companies, Southern Power, SEGCO, SCS, Southern LINC, and other subsidiaries are estimated as follows:
------------------------------------------------------------ 2003 2004 2005 -------------------------------- (in millions) Alabama Power $ 643 $ 787 $ 948 Georgia Power 759 781 806 Gulf Power 108 150 156 Mississippi Power 76 86 75 Savannah Electric 41 51 44 SEGCO 13 22 5 SCS 22 25 20 Southern LINC 28 22 22 Southern Power 377 381 278 Other 8 3 - ------------------------------------------------------------ Southern Company system $2,075 $2,308 $2,354 ============================================================
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Estimated construction costs in 2003 are expected to be apportioned approximately as follows: (in millions)
* SCS, Southern LINC and other businesses plan capital additions to general plant in 2003 of $22 million, $28 million and $8 million, respectively, while SEGCO plans capital additions of $13 million to generating 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; 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.
By the end of 2005, Southern Power plans to have approximately 6,600 megawatts of available generating capacity in commercial operation. At December 31, 2002, 2,400 megawatts were in commercial operation. Significant construction of transmission and distribution facilities and upgrading of generating plants will also be continuing, including expenditures to meet environmental compliance requirements.
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.)
See Item 1 - BUSINESS - "Regulation - Environmental Statutes and Regulation" herein for information with respect to certain existing and proposed environmental requirements and Item 2
Item 2. PROPERTIES
Electric Properties - The Electric Utilities
The operating companies, Southern Power and SEGCO, at December 31, 2002, owned and/or operated 34 hydroelectric generating stations, 33 fossil fuel generating stations, three nuclear generating stations and eight 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 1,045,000 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 2,134,500 ---------
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 21,275,243 -----------
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 -----------
Atkinson Atlanta, GA 78,720 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 1,864,909 - ---------
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 ---------
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------------------------------------------------------------------ Generating Station Location Nameplate Capacity ------------------------------------------------------------------ (Kilowatts) Boulevard Savannah, GA 59,100 Kraft Port Wentworth, GA 22,000 McIntosh Units 5&6 Effingham County, GA 160,000 ------- Savannah Electric Total 241,100 ------- 241,100
Dahlberg 756,000 (12) -------- Southern Power Total 756,000 -------
Gaston (SEGCO) Wilsonville, AL 19,680 (7) ----------- Total Combustion Turbines 3,882,141 -----------
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 Gulf Power Total 619,650 -------
Daniel (Leased) Pascagoula, MS Mississippi Power Total 1,070,424 ---------
Franklin 538,900 (12) Wansley 1,073,000 (12) --------- Southern Power Total 1,611,900 ---------
Total Combined Cycle 4,372,398 ---------
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 154,200 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 1,599,600 -----------
------------------------------------------------------------------ Generating Station Location Nameplate Capacity ------------------------------------------------------------------ (Kilowatts) (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 (13) 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 2,677,336 ----------- Total Generating Capacity 36,351,616 ===========
------------------------------------------------------------------ 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)In connection with various PPAs, Southern Power conducts unit testing to set contract capacity availability. At December 31, 2002, such capacity was as follows: 810,000 kilowatts - Dahlberg 561,300 kilowatts - Franklin 1,134,500 kilowatts - Wansley (13)Capacity shown is Georgia Power's portion (25.4%) of total plant capacity. OPC operates the plant. I-25
Except as discussed below under "Titles to Property," the principal plants and other important units of the operating companies, Southern Power and SEGCO are owned in fee by the respective companies. It is the opinion of management of each such company that its operating properties are adequately maintained and are substantially in good operating condition.
Mississippi Power owns a 79-mile length of 500-kilovolt transmission line which is leased to Entergy Gulf States. The line, completed in 1984, extends from Plant Daniel to the Louisiana state line. Entergy Gulf States is paying a use fee over a 40-year period covering all expenses and the amortization of the original $57 million cost of the line. At December 31, 2002, the unamortized portion of this cost was approximately $32.1 million.
The all-time maximum demand on the operating companies, Southern Power and SEGCO was 32,355,000 kilowatts and occurred in July 2002. 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 operating companies, Southern Power and SEGCO at that time was 13.3%. For additional information on peak demands, reference is made to Item 6 - SELECTED FINANCIAL DATA herein.
Alabama Power and Georgia Power will incur significant costs in decommissioning their nuclear units at the end of their useful lives. (See Item 1 - BUSINESS - "Regulation - Atomic Energy Act of 1954" and Note 1 to the financial statements of Southern Company, Alabama Power and Georgia Power under the heading "Depreciation and Nuclear Decommissioning" in Item 8 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. 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 described below) as agent for the joint owners.
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.
Additionally, jointly-owned facilities also include Southern Power's 65% undivided interest in Stanton Unit A and related facilities jointly owned with the Orlando Utilities Commission, the Kissimmee Utility Authority and the
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Florida Municipal Power Agency. Currently under construction near Orlando, Florida, this project will be a 610 megawatt combined cycle unit and is scheduled for commercial operation in October 2003.
Titles to Property
The 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, Mississippi Power's combined cycle units at Plant Daniel 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 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)
On November 3, 1999, the EPA brought a civil action in the U.S. District Court in Georgia against Alabama Power. The complaint alleges violations of the New Source Review provisions of the Clean Air Act with respect to coal-fired generating facilities at Alabama Power'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 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. The EPA concurrently issued a notice of violation relating to these specific facilities, as well as Plants Greene County and Gaston. On August 1, 2000, the U.S. District Court granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia. On January 12, 2001, the EPA re-filed its claims against Alabama Power in federal district court in Birmingham, Alabama. Alabama Power's case has been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the TVA. The TVA appeal involves many of the same legal issues raised by the actions against Alabama Power. Because the outcome of the TVA appeal could have a significant adverse impact on Alabama Power, Alabama Power is a party to that case as well. In February 2003, the U.S. District Court in Alabama extended the stay of the EPA litigation proceeding in Alabama until the earlier of May 6, 2003 or a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the related litigation involving TVA.
Alabama Power 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. 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.
(2) United States of America v. Georgia Power and Savannah Electric (United States District Court for the Northern District of Georgia)
On November 3, 1999, the EPA brought a civil action in the U.S. District Court in Georgia against Georgia Power. The complaint alleges violation of the New Source Review provisions of the Clean Air Act with respect to coal-fired generating facilities at Georgia Power's Plants Bowen and Scherer. 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 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. On March 27, 2001, the U.S. District Court granted the EPA's motion to amend its complaint to add the alleged violations at Savannah Electric's Plant Kraft and to add Savannah Electric as a defendant. The EPA concurrently issued a notice of violation relating to these two Georgia Power plants and Savannah Electric's Plant Kraft.
The cases have been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the TVA. The TVA appeal involves many of the same legal issues raised by the actions against Georgia Power and Savannah Electric. Because the outcome of the TVA appeal could have a significant adverse impact on Georgia Power, Georgia Power has been a party to that case as well. On August 21, 2002, the U.S. District Court in Georgia denied the EPA's motion to reopen the Georgia case. The denial was without prejudice to the EPA to refile the
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Item 3. LEGAL PROCEEDINGS (Continued)
motion at a later date, which he EPA has not done at this time.
Georgia Power and Savannah Electric believe that they complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. An adverse outcome of these matters could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties.
(3) Cooper et al. v. Georgia Power, Southern Company, SCS and Energy Solutions (Superior Court of Fulton County, Georgia)
On July 28, 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 subsidiary of Southern Company, Energy Solutions (now Southern Management Development), 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 United States Court of Appeals for the Eleventh Circuit seeking permission to file an appeal of the October 2001 decision. In March 2002, the Eleventh Circuit denied the plaintiffs' petition. 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. The parties await the court's ruling on the seven motions for summary judgment. The final outcome of the case cannot now be determined.
(4) 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.
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.
The final outcome of these matters cannot now be determined.
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 "Other Environmental Contingencies," respectively.
(5) In re: Mobile Energy Services Company, LLC; In re: Mobile Energy Services Holdings, Inc. (U.S. Bankruptcy Court for the Southern District of Alabama)
In August 2000, MESH filed a proposed plan of reorganization with the U.S. Bankruptcy Court. The proposed plan of reorganization was most recently amended on December 13, 2001. Southern Company expects that
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Item 3. LEGAL PROCEEDINGS (Continued)
approval of a plan of reorganization would result in a termination of Southern Company's ownership interest in MESH but would not affect Southern Company's continuing guarantee obligations discussed earlier. The final outcome of this matter cannot now be determined.
Reference is made to Note 3 to Southern Company's financial statements in Item 8 herein under the heading "Mobile Energy Services' Petition for Bankruptcy."
(6) Gordon v. Southern Company et al. (United States District Court for the Southern District of California) and (7) Pier 23 Restaurant v. Southern Company et al. (United States District Court for the Northern District of California)
Prior to the spin off of Mirant, Southern Company was named as a defendant in two lawsuits filed in the superior courts of California alleging that certain owners of electric generation facilities in California, including Southern Company, engaged in various unlawful and anticompetitive acts that served to manipulate wholesale power markets and inflate wholesale electricity prices in California. One lawsuit naming Southern Company, Mirant and other generators as defendants alleged that, as a result of the defendants' conduct, customers paid approximately $4 billion more for electricity than they otherwise would have and sought an award of treble damages, as well as other injunctive and equitable relief. The other suit likewise sought treble damages and equitable relief. The allegations in the two lawsuits in which Southern Company was named seemed to be directed to activities of subsidiaries of Mirant. In the fall of 2001, the plaintiffs voluntarily dismissed Southern Company without prejudice from the two lawsuits in which it had been named as a defendant. Prior to being dismissed, Southern Company had notified Mirant of its claim for indemnification for costs associated with the lawsuits under the terms of the master separation agreement that governs the spin off of Mirant. Mirant had undertaken the defense of the lawsuits. Plaintiffs would not be barred by their own dismissal from naming Southern Company in some future lawsuit, but management believes that the likelihood of Southern Company having to pay damages in any such lawsuit is remote.
(8) California Electricity Markets Investigation
Southern Company has received a subpoena to provide information to a federal grand jury in the Northern District of California. The subpoena covers a number of broad areas, including specific information regarding electricity production and sales activities in California. Southern Company's former subsidiary, 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 is fully cooperating in the investigation.
(9) In re: Mirant Corporation Securities Litigation (United States District Court for the North District of Georgia)
In November 2002, Southern Company, along with certain former and current senior officers of Southern Company and 12 underwriters of Mirant's initial public offering, were added as defendants in a class action lawsuit that several Mirant shareholders originally filed against Mirant and certain Mirant officers in May 2002. The original lawsuit against Mirant and its officers 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 United States District Court for the Northern District of Georgia. The November 2002 amended complaint
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Item 3. LEGAL PROCEEDINGS (Continued)
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. For more information, see Note 11 to the financial statements of Southern Company in Item 8 herein. The lawsuit purports to include persons who acquired Mirant securities on the open market or pursuant to an offering between September 26, 2000, and September 5, 2002. The amended complaint does not allege any improper trading and marketing activity, accounting errors, or material misstatements or omissions on the part of Southern Company but seeks to impose liability on Southern Company based on allegations that Southern Company was a "control person" as to Mirant. On February 14, 2003, Southern Company filed a motion seeking to dismiss all claims against Southern Company. However, the final outcome of this matter cannot now be determined.
(10) 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 U.S. District Court in Georgia against Georgia Power for alleged violations of the Clean Air Act 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 January 27, 2003, Georgia Power filed a response to the complaint. Georgia Power also filed a motion to dismiss the allegations regarding emission offsets and hazardous air pollutants. 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.
(11) Right of Way Litigation
In 2002, certain subsidiaries of Southern Company, including Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, and Southern Telecom (collectively, defendants), were named as defendants in numerous lawsuits brought by landowners 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. Defendants believe 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.
(12) 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. If the verdict is not overturned, the plaintiff will also be
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Item 3. LEGAL PROCEEDINGS (Continued)
entitled to recover attorney's fees. Gulf Power intends to seek a new trial; however, if it is not successful in obtaining a new trial, Gulf Power intends to pursue an appeal. 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.
Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company and its subsidiaries are also 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 currently filed against Southern Company and its subsidiaries cannot be predicted at this time; however, after consultation with legal counsel, management does not anticipate that the liabilities, if any, arising from such 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, 2002.
H. Allen Franklin Chairman, President, Chief Executive Officer and Director Age 58 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 54 Elected in 2001. Previously served as President and Chief Executive Officer of Mississippi Power from March 1995 to May 2001.
David M. Ratcliffe Executive Vice President Age 54 Elected in 1999. He also has served as 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; and Senior Vice President of Southern Company from March 1995 to March 1998.
Leonard J. Haynes Executive Vice President and Chief Marketing Officer Age 52 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 50 Elected in 2001. Previously served as President and Chief Executive Officer of Savannah Electric from 1997 until 2001.
Gale E. Klappa Executive Vice President, Chief Financial Officer and Treasurer Age 52 Elected in 2001. Previously served as Financial Vice President, Chief Financial Officer and Treasurer from March 2001 to May 2001; Senior Vice President and Chief Strategic Officer of Southern Company from October 1999 to March 2001; President of Mirant's North America Group and Senior Vice President of Mirant from December 1998 to October 1999; and as President and Chief Executive Officer of Western Power Distribution, a subsidiary of Mirant located in Bristol, England, from September 1995 to December 1998.
Charles D. McCrary Executive Vice President Age 51 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; and as Executive Vice President of Alabama Power from 1994 through February 1998.
W. Paul Bowers Executive Vice President of SCS and President and Chief Executive Officer of Southern Power since May 2001 Age 45 Elected in 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; and Senior Vice President of Retail Marketing for Georgia Power from 1995 to 1998.
W. G. Hairston, III President and Chief Executive Officer of Southern Nuclear since 1993. Age 58
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, 2002) 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, 2002.
Charles D. McCrary President, Chief Executive Officer and Director Age 51 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. Previously served as Executive Vice President of External Affairs at Alabama Power from April 1994 through February 1998.
William B. Hutchins, III Executive Vice President, Chief Financial Officer and Treasurer Age 59 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 54 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; and Vice President of Human Resources for Southern Company from May 1995 to March 1998.
Steven R. Spencer Executive Vice President Age 47 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 53 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 26, 2002) 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, 2002.
David M. Ratcliffe President, Chief Executive Officer and Director Age 54 Elected as an Executive Officer in 1998 and as Director in 1999. Served as President and Chief Executive Officer since June 1999. Previously served as Executive Vice President, Treasurer and Chief Financial Officer of Georgia Power from 1998 to 1999; and as Senior Vice President of Southern Company from March 1995 to March 1998.
William C. Archer, III Executive Vice President Age 54 Elected in 1995. Served as Executive Vice President of External Affairs since 1995.
Allen L. Leverett Executive Vice President, Treasurer and Chief Financial Officer Age 36 Elected in 2002. Previously served as Vice President and Treasurer of SCS and Assistant Treasurer of Georgia Power from 2000 to 2002; and as Vice President, Financial Planning & Analysis from 1997 to 2000.
Judy M. Anderson Senior Vice President Age 54 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 48 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 55 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.
James K. Davis Senior Vice President Age 62 Elected in 1993. Served as Senior Vice President of Corporate Relations since 1993, with Employee Relations being added to his responsibilities in 2000.
Leslie R. Sibert Vice President Age 40 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 44 Elected in 2001. Served as Senior Vice President of Fossil and Hydro since 2001. Previously served as Vice President and Chief People Officer of Southern Company from 1998 to 2001; and as Senior Vice President of Public Relations and Corporate Services at Alabama Power from 1995 to 1998.
The officers of Georgia Power were elected for a term running from the last annual meeting of the directors (May 15, 2002) for one year until the next annual meeting or until their successors are elected and have qualified, except for Mr. Leverett, whose election was effective May 25, 2002.
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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, 2002.
Thomas A. Fanning President, Chief Executive Officer and Director Age 45 Elected in 2002. Previously served as Executive Vice President, Treasurer and Chief Financial Officer of Georgia Power from 1999 to 2002; and as Senior Vice President of SCS and Chief Information Officer for Southern Company from 1995 to June 1999.
Francis M. Fisher, Jr. Vice President Age 54 Elected in 1989. Served as Vice President of Power Delivery and Customer Operations since 1996.
John E. Hodges, Jr. Vice President Age 59 Elected in 1989. Served as Vice President of Marketing and Employee/External Affairs since 1996.
Ronnie R. Labrato Vice President, Chief Financial Officer and Comptroller Age 49 Elected in 2000. Previously served as Comptroller and Chief Financial Officer from 2000 to 2001 and Controller from 1992 to 2000.
Warren E. Tate Vice President, Secretary/Treasurer and Regional Chief Information Officer Age 60 Elected in 2000. Served as Vice President since 2001, also serves as Secretary/Treasurer and Regional Chief Information Officer since 1996.
Gene L. Ussery, Jr. Vice President Age 53 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 (May 17, 2002) 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, 2002.
Michael D. Garrett President, Chief Executive Officer and Director Age 53 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; and Senior Vice President of External Affairs of Alabama Power from February 1994 to March 1998.
H. E. Blakeslee Vice President Age 62 Elected in 1984. Served as Vice President of Customer Services and Retail Marketing since 1984.
Don E. Mason Vice President Age 61 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 50 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 53 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.
The officers of Mississippi Power were elected for a term running from the last annual meeting of the directors (April 24, 2002) for one year until the next annual meeting or until their successors are elected and have qualified.
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PART II
Item 5.
Item 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
(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 $26.78 $24.49 Second Quarter 28.39 25.65 Third Quarter 29.02 23.89 Fourth Quarter 30.85 25.17
First Quarter $21.65 $16.15 Second Quarter 23.88 20.89 Third Quarter 26.00 22.05 Fourth Quarter 25.98 22.30
-------------------------------------------------------
There is no market for the other registrants' common stock, all of which is owned by Southern Company. On February 28, 2003, the closing price of Southern Company's common stock was $28.21.
(b) Number of Southern Company's common stockholders of record at December 31, 2002: 141,784
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 operating companies to their stockholder(s) for the past two years were as follows:
--------------------------------------------------------- Registrant Quarter 2002 2001 --------------------------------------------------------- (in thousands)
Southern Company First $ 234,272 $ 228,320 Second 236,154 229,611 Third 242,850 231,192 Fourth 244,309 232,935
Alabama Power First 107,750 101,200 Second 107,750 97,600 Third 107,750 97,600 Fourth 107,750 97,500
Georgia Power First 135,725 134,500 Second 135,725 130,900 Third 135,725 130,900 Fourth 135,725 131,000
Gulf Power First 16,375 13,500 Second 16,375 13,300 Third 16,375 13,300 Fourth 16,375 13,175
Mississippi First 15,875 12,800 Power Second 15,875 12,500 Third 15,875 12,500 Fourth 15,875 12,400
Savannah First 5,675 5,500 Electric Second 5,675 5,400 Third 5,675 5,400 Fourth 5,675 5,400 ---------------------------------------------------------
Southern Power did not pay a dividend in 2002 or 2001.
The dividend paid per share by Southern Company was 33.5(cent) for each quarter of 2001 and the first two quarters of 2002 and 34.25(cent) for the two remaining quarters in 2002. The dividend paid on Southern Company's common stock for the first quarter of 2003 was 34.25(cent) per share.
II-1
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 Notes 7 of Southern Company and Mississippi Power, Note 8 of Gulf Power and Note 6 of 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, 2002 were as follows:
---------------------------------------------------------- Retained Restricted Earnings Amount ------------------ ------------- (in millions) Alabama Power $ 1,250 $ - Georgia Power 1,945 - Gulf Power 162 127 Mississippi Power 196 118 Savannah Electric 110 68 Southern Power 62 - Consolidated 4,875 313 ----------------------------------------------------------
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-53 and II-54.
Alabama Power. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-93 and II-94.
Georgia Power. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-134 and II-135.
Gulf Power. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-171 and II-172.
Mississippi Power. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-210 and II-211.
Savannah Electric. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at pages II-246 and II-247.
Southern Power. Reference is made to information under the heading "Selected Financial and Operating Data," contained herein at page II-275.
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-9 through II-23.
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-58 through II-70.
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-98 through II-110.
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-139 through II-151.
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-176 through II-188.
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-215 through II-227.
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-251 through II-259.
II-2
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Reference is made to information in Southern Company's "Management's Discussion and Analysis - Market Price Risk" in Item 7 herein and to Notes 1 and 8 to Southern Company's financial statements under the heading "Financial Instruments" contained herein on pages II-17, II-35 and II-47, respectively.
Reference is also made to "Management's Discussion and Analysis - Exposure to Market Risks" in Item 7 of Alabama Power, Georgia Power, Gulf Power, Savannah Electric and Southern Power contained herein at pages II-64, II-104, II-144, II-220, and II-257, respectively. Reference is also made to "Management's Discussion and Analysis - Market Price Risk" in Item 7 of Mississippi Power contained herein at page II-182. Further reference is made to Note 1 to the financial statements in Item 8
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO 2002 FINANCIAL STATEMENTS
II-4
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
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
II-6
MANAGEMENT'S REPORT Southern Company and Subsidiary Companies 2002 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 system of internal accounting controls is 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 five 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/Gale E. Klappa Gale E. Klappa Executive Vice President, Chief Financial Officer, and Treasurer February 17, 2003
II-7
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of Southern Company
We have audited the accompanying consolidated balance sheet and consolidated statement of capitalization of Southern Company and Subsidiary Companies as of December 31, 2002, and the related consolidated statements of income, comprehensive income, common stockholders' equity, and cash flows for the year 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 audit. The consolidated financial statements of Southern Company and Subsidiary Companies as of December 31, 2001, and for each of the two years then ended 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 audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the 2002 consolidated financial statements (pages II-24 to II-52) present fairly, in all material respects, the financial position of Southern Company and Subsidiary Companies at December 31, 2002, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
/s/Deloitte & Touche LLP Atlanta, Georgia February 17, 2003
THE FOLLOWING REPORT OF INDEPENDENT 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 through 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
II-8
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Southern Company and Subsidiary Companies 2002 Annual Report
RESULTS OF OPERATIONS - ---------------------
Overview of Consolidated Earnings and Dividends
Earnings
Southern Company's financial performance in 2002 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 $1.3 billion increased 17.6 percent over income from continuing operations reported in 2001. Net income from continuing operations was $1.1 billion in 2001 and $994 million in 2000. This was a 12.7 percent and 8.6 percent increase in 2001 and 2000, respectively. Basic earnings per share from continuing operations in 2002 were $1.86 per share, $1.62 in 2001, and $1.52 in 2000. Dilution -- which factors in additional shares related to stock options -- decreased earnings per share by 1 cent in 2002 and 2001 and had no impact in 2000.
In April 2000, Southern Company announced an initial public offering of up to 19.9 percent of Mirant Corporation (Mirant) and intentions to spin off its remaining ownership of 272 million Mirant shares. On April 2, 2001, the tax-free distribution of Mirant shares was completed. As a result of the spin off, Southern Company's financial statements and related information reflect Mirant as discontinued operations. Therefore, the focus of Management's Discussion and Analysis is on Southern Company's continuing operations. The following chart shows earnings from continuing and discontinued operations:
Basic Earnings Per Share -------------------------- 2002 2001 2000 - -------------------------------------------------------------- Earnings from -- Continuing operations $1.86 $1.62 $1.52 Discontinued operations - 0.21 0.49 - -------------------------------------------------------------- Total earnings $1.86 $1.83 $2.01 ==============================================================
Dividends
Southern Company has paid dividends on its common stock since 1948. Dividends paid per share on common stock in 2002 were $1.355 and $1.34 in 2001 and 2000. The quarterly dividend was increased in September 2002 to 341/4 cents per share - -- or $1.37 annually -- from 331/2 cents. In January 2003, Southern Company declared a quarterly dividend of 341/4 cents per share. This is the 221st consecutive quarter that Southern Company has paid a dividend equal to or higher than the previous quarter. Our goal for the dividend payout ratio is a range of 70 to 75 percent and the payout ratio was 72.8 percent for 2002.
Southern Company Business Activities
Discussion of the results of continuing operations is focused on Southern Company's primary business of electricity sales by the 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 rates. The remaining portion of Southern Company's other business activities includes alternative fuels, energy-related products and services, leveraged leasing activities, and the parent holding company. A condensed income statement for the other businesses is shown later.
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 regulated retail and wholesale and competitive generation business is as follows:
Increase (Decrease) Amount From Prior Year -------- ----------------------- 2002 2002 2001 2000 - -------------------------------------------------------------- (in millions) Operating revenues $10,206 $ 300 $ 46 $735 - -------------------------------------------------------------- Fuel 2,786 209 13 236 Purchased power 449 (269) 41 268 Other operation and maintenance 2,751 262 19 40 Depreciation and amortization 989 (155) 9 89 Taxes other than income taxes 555 22 1 11 - -------------------------------------------------------------- Total operating expenses 7,530 69 83 644 - -------------------------------------------------------------- Operating income 2,676 231 (37) 91 Other income, net (17) (32) 51 2 Interest expenses and other, net 585 (24) (25) 29 Income taxes 778 76 (1) 28 - -------------------------------------------------------------- Net income $ 1,296 $ 147 $ 40 $ 36 ==============================================================
II-9
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2002 Annual Report
Revenues
Details of electric operating revenues are as follows:
2002 2001 2000 - -------------------------------------------------------------- (in millions) Retail -- prior year $ 8,440 $8,600 $8,090 Change in -- Base rates 33 23 (36) Sales growth 98 61 115 Weather 158 (177) 95 Fuel cost recovery and other (1) (67) 336 - -------------------------------------------------------------- Total retail 8,728 8,440 8,600 - -------------------------------------------------------------- Sales for resale -- Within service area 389 338 377 Outside service area 779 836 600 - -------------------------------------------------------------- Total sales for resale 1,168 1,174 977 - -------------------------------------------------------------- Other electric operating revenues 310 292 283 - -------------------------------------------------------------- Electric operating revenues $10,206 $9,906 $9,860 ============================================================== Percent change 3.0% 0.5% 8.1% - ---------------------------------------------------------------
Retail revenues increased $288 million in 2002, declined $160 million in 2001, and rose $510 million in 2000. The significant factors driving these changes are shown in the table above.
Electric rates -- for the operating companies -- 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.
Sales for resale revenues within the service area of $389 million for 2002 were near the same level as 2000, which reflected closer to normal weather-adjusted sales. 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, which significantly reduced energy requirements from these customers. Sales for resale within the service area for 2000 were up from the prior year as a result of additional demand for electricity during the hot summer.
Revenues from energy sales for resale outside the service area were down 7.1 percent in 2002 after having increased 39 percent in 2001 and 27 percent in 2000. 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 $306 million since 1999 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. Capacity revenues reflect the recovery of fixed costs and a return on investment under the unit power sales contracts, 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:
2002 2001 2000 - -------------------------------------------------------------- (in millions) Unit power -- Capacity $175 $170 $177 Energy 198 201 178 Other long term -- Capacity 100 112 42 Energy 306 353 203 - -------------------------------------------------------------- Total $779 $836 $600 ==============================================================
Capacity revenues for unit power contracts in 2002, 2001, and 2000 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. See Note 5 to the financial statements for additional information.
Energy Sales
Changes in revenues are influenced heavily by the volume of energy sold each year. Kilowatt-hour sales for 2002 and the percent change by year were as follows:
Amount Percent Change (billions of ------ --------------------------- kilowatt-hours) 2002 2002 2001 2000 - -------------------------------------------------------------- Residential 48.8 9.5% (3.6)% 6.5% Commercial 48.2 2.8 1.5 6.6 Industrial 53.9 1.8 (6.8) 1.0 Other 1.0 2.3 0.7 2.7 ----- Total retail 151.9 4.5 (3.2) 4.3 Sales for resale -- Within service area 10.6 12.9 (2.0) 1.5 Outside service area 21.9 2.7 24.4 33.0 ----- - Total 184.4 4.7 (0.5) 6.4 ==============================================================
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2002 Annual Report
Residential energy sales in 2002 reflected a substantial increase compared with 2001 as a result of weather and a 1.6 percent increase in new customers. Commercial sales continued to show steady growth while industrial sales increased somewhat over the depressed results of recent years. 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. In 2000, 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 an increase in customers served. Also in 2000, commercial sales continued to reflect the strong economy in the Southeast. Energy sales to retail customers are projected to increase at an average annual rate of 1.9 percent during the period 2003 through 2013.
Sales to customers outside the service area under more recent long-term contracts increased kilowatt-hour sales by 1.0 billion, 3.9 billion, and 2.2 billion in 2002, 2001, and 2000, respectively. These sales reflected the expansion of the competitive wholesale generation business discussed earlier. Unit power energy sales decreased 3.3 percent in 2002, increased 2.7 percent in 2001, and increased 21 percent in 2000. These changes are influenced by fluctuations in prices for oil and natural gas. These are the primary fuel sources for the unit power sales customers. 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 2002 were $7.5 billion, an increase of $69 million over 2001 expenses. Electricity production costs exceeded last year's 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. This increase was driven by additional maintenance projects in 2002 as compared to 2001. 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. For more information regarding this rate action, see Note 3 to the financial statements under "Georgia Power Retail Rate Orders."
In 2001, electric operating expenses of $7.5 billion 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. In 2000, operating expenses of $7.4 billion increased $644 million compared with the prior year. The costs to produce electricity in 2000 increased by $498 million to meet higher energy requirements. Non-production operation and maintenance expenses increased $46 million in 2000. Depreciation and amortization expenses in 2000 increased $89 million, of which $50 million resulted from additional accelerated amortization by Georgia Power.
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 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 -- within the service area -- were as follows:
2002 2001 2000 - -------------------------------------------------------------- Total generation (billions of kilowatt-hours) 183 174 174 Sources of generation (percent) -- Coal 69 72 78 Nuclear 16 16 16 Gas 12 9 4 Hydro 3 3 2 Average cost of fuel per net kilowatt-hour generated (cents) 1.61 1.56 1.51 - --------------------------------------------------------------
Fuel and purchased power costs to produce electricity were $3.24 billion in 2002, a decrease of $60 million or 1.8 percent below the prior year costs. An
II-11
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2002 Annual Report
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.
In 2001, fuel and purchased power costs of $3.3 billion increased $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 fuel and purchased power costs increased $504 million in 2000 as a result of a 10.6 billion increase in kilowatt-hours being sold compared with 1999. This increased demand was met by purchasing some 2.5 billion additional kilowatt-hours and using generation with higher unit fuel cost than in 1999.
Total interest charges and other financing costs in 2002 declined by $24 million as a result of much lower interest rates on short-term debt and continued refinancing of higher-cost long-term securities. Total interest charges and other financing costs in 2001 decreased $25 million from amounts reported in the previous year. The decline reflected substantially lower short-term interest rates that offset new financing costs. Total interest charges and other financing costs in 2000 increased $29 million, reflecting some additional external financing for new generating units.
Other Business Activities
Southern Company's other business activities include the parent company -- which does not allocate operating expenses to business units -- telecommunications, energy services, leasing, alternative fuels, and natural gas marketing. These businesses are classified in general categories and may comprise one or more of the following subsidiaries. Southern LINC provides digital wireless communications services to the integrated Southeast utilities and also markets these services to the public within the Southeast; Southern Telecom provides fiber optics services; 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. Southern Company Holdings invests in alternative fuel projects and leveraged lease projects, which currently receive tax benefits that contribute significantly to the economic results of these investments.
A condensed income statement for Southern Company's other business activities is shown below:
Increase (Decrease) Amount From Prior Year ------- ----------------------- 2002 2002 2001 2000 - -------------------------------------------------------------- (in millions) Operating revenues $ 343 $ 94 $ 43 $ 14 - -------------------------------------------------------------- Operation and maintenance 378 106 29 6 Depreciation and amortization 58 29 (7) (57) Taxes other than income taxes 2 - (2) 2 - -------------------------------------------------------------- Total operating expenses 438 135 20 (49) - -------------------------------------------------------------- Operating income (95) (41) 23 63 Equity in losses of unconsolidated subsidiaries (92) (39) (31) (6) Leveraged lease income 58 (1) (2) 30 Other income, net - (10) 5 (3) Interest expenses 99 (36) (62) 80 Income taxes (250) (106) (29) (39) - -------------------------------------------------------------- Net income $ 22 $ 51 $ 86 $ 43 ==============================================================
Operating revenues reflect Southern LINC's increased revenues of $32 million, $12 million, and $32 million in 2002, 2001, and 2000, respectively, as a result of increased wireless subscribers. Southern Company GAS began operations in August 2002 and recorded revenues of $68 million for the year. Revenues for 2001 also increased $30 million from the operations of a subsidiary formed in April 2001 that provides services related to alternative fuel products. The increase in revenues for 2000 was partially offset by a $19 million decrease in Southern Company Energy Solutions' revenues from the prior year, which included the impact of several major contracts.
The $106 million increase in operating and maintenance expense in 2002 was driven primarily by Southern Company GAS' natural gas purchases and other operating expenses of $60 million, increases in expenses of $19 million at Southern LINC as a result of their additional subscribers, and a $30 million increase in expenses related to alternative fuel product services.
The changes in depreciation expense for all three periods were primarily a result of asset write downs. The 2002 increase 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2002 Annual Report
Southern LINC. The 2001 and 2000 decreases relate to investment write offs in 2000 and 1999, as discussed in Note 3 to the financial statements under "Mobile Energy Services."
The increases in equity in losses of unconsolidated subsidiaries reflect the results of additional investments in alternative 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 $108 million in 2002, $71 million in 2001, and $23 million in 2000.
Interest expense changes from the prior year reflected lower interest rates and lower amounts of debt outstanding for the parent company in 2002 and 2001. The increase in 2000 was related to additional borrowings.
Effects of Inflation
The 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 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. A major factor is the ability of the operating companies to maintain a stable regulatory environment and to achieve energy sales growth while containing costs. Another major factor is the profitability of the competitive market-based wholesale generating business.
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 short and long-term contracts with neighboring utilities, energy conservation practiced by customers, the price elasticity of demand, and the rate of economic growth in the service area.
The 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.
Southern Power currently has general authorization from the Federal Energy Regulatory Commission (FERC) to sell power to nonaffiliates at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. As with any seller that has been authorized to sell at market-based rates, the FERC retains the authority to modify or withdraw Southern Power's market-based rate authority 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.
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 $117 million in 2002. Future pension income is dependent on several factors including trust earnings and changes to the plan. Current estimates indicate a reversal of recording pension income to recording pension expense by as early as 2005. Postretirement benefit costs for Southern Company were $99 million in 2002 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 operating companies, pension income and postretirement benefit costs are a component of the regulated rates and do not have a significant 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 2002 Annual Report
Southern Company currently receives tax benefits related to investments in alternative fuel partnerships and leveraged lease agreements for energy generation, distribution, and transportation assets that contribute significantly to the economic results for these projects. Changes in Internal Revenue Service interpretations of existing regulations or challenges to the company's positions could result in reduced availability or changes in the timing of such tax benefits. The net income impact of these investments totaled $62 million, $52 million, and $28 million in 2002, 2001, and 2000, respectively. See Note 1 to the financial statements under "Leveraged Leases" and Note 6 for additional information and related income taxes.
Mississippi Power and Southern Power have capacity sales contracts with subsidiaries of Dynegy Inc. (Dynegy). Dynegy is currently experiencing liquidity problems, and its credit rating is now below investment grade. Minimum capacity revenues under these contracts average approximately $13 million annually through May 2005 for Southern Power and $21 million annually for Mississippi Power through May 2011. Dynegy has provided letters of credit expiring in April 2003 totaling $20 million -- approximately 18 months of capacity payments -- to Southern Power and $26 million -- approximately 15 months of capacity payments - -- to Mississippi Power. In addition, two one-year letters of credit totaling $50 million -- approximately 14 months of capacity payments -- were provided in April 2002 as security for obligations of Dynegy affiliates under the Plant Franklin Unit 3 purchase power agreement beginning in 2005. These letters of credit can be drawn in the event of a default under the purchase power agreement or the failure to renew the letters of credit prior to expiration. In the event of such a default, and if Mississippi Power and Southern Power are unable to resell that capacity into the market, future earnings could be affected. See Note 5 to the financial statements for additional information. The outcome cannot now be determined.
In November 2002, Mirant announced that it had identified accounting errors in previously issued financial statements primarily related to its risk management and marketing operations and that its net income for January 1999 through 2001 was overstated by $51 million. Although the impact on specific quarters has not yet been determined, Mirant's new independent auditors are reauditing 2001 and 2000 financial statements. This reaudit is not expected to be completed until Mirant files its Form 10-K for the year ended December 31, 2002. If the reaudit of Mirant's financial statements results in adjustments prior to Southern Company's spin off of Mirant, Southern Company's earnings from discontinued operations for such periods could be affected. The impact of any such adjustments would not affect Southern Company's 2002 or any future financial statements. Based on the nature and amount of Mirant's announced accounting errors, Southern Company's management does not currently anticipate that a reaudit of its financial statements will be necessary.
Proposed nuclear security legislation is expected to be introduced in the 108th Congress. The Nuclear Regulatory Commission is also considering additional security measures for licensees that could require immediate implementation. Any such requirements could have a significant impact on Southern Company's nuclear power plants and result in increased operation and maintenance expenses as well as additional capital expenditures. The impact of any new requirements would depend upon the development and implementation of the regulations.
Southern Company is involved in various matters being litigated. See Note 3 to the financial statements for information regarding material issues that could possibly affect future earnings.
Compliance costs related to current and future environmental laws and regulations could affect earnings if such costs are not fully recovered. The Clean Air Act and other important environmental items are discussed later under "Environmental Matters."
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 allows independent power producers (IPPs) to access a utility's transmission network in order to sell electricity to other utilities. This enhanced the incentive for IPPs to build power plants for a utility's large industrial and commercial customers where retail access is allowed and to sell energy to other utilities. Also, electricity sales for resale rates were affected by numerous new energy suppliers, including power marketers and brokers.
This past year, merchant energy companies and traditional electric utilities with significant energy marketing and trading activities came under severe financial pressures. Many of these companies have completely exited or drastically reduced all energy marketing and trading activities and sold foreign
II-14
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2002 Annual Report
and domestic electric infrastructure assets. Southern Company has not experienced any material 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, which are both supplemented by limited energy trading activities.
Although the Energy Act does not provide for retail customer access, it was a major catalyst for recent 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 a result of that crisis, many states, including those in Southern Company's retail service area, have either discontinued or delayed consideration of initiatives involving retail deregulation.
Continuing to be a low-cost producer could provide opportunities to increase market share and profitability in markets that evolve with changing regulation and competition. Conversely, 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.
The Energy Act amended the Public Utility Holding Company Act of 1935 (PUHCA) to facilitate acquisitions of interests in exempt wholesale generators, which sell electricity exclusively for resale. Southern Company is working to maintain and expand its share of wholesale energy sales in the Southeast. In January 2001, Southern Company formed a new subsidiary -- Southern Power Company. This subsidiary constructs, owns, and manages wholesale generating assets in the Southeast. Southern Power is the primary growth engine for Southern Company's competitive wholesale market-based energy business. By the end of 2005, Southern Power plans to have approximately 6,600 megawatts of available generating capacity in commercial operation. At December 31, 2002, 2,400 megawatts were in commercial operation.
FERC Matters
In December 1999, the FERC issued its final rule on Regional Transmission Organizations (RTOs). The order encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Southern Company has submitted a series of status reports informing the FERC of progress toward the development of a Southeastern RTO. In these status reports, Southern Company explained that it is developing a for-profit RTO known as SeTrans with a number of non-jurisdictional cooperative and public power entities. In 2001, Entergy Corporation and Cleco Power joined the SeTrans development process. In 2002, the sponsors of SeTrans established a Stakeholder Advisory Committee, which will participate in the development of the RTO, and held public meetings to discuss the SeTrans proposal. On October 10, 2002, the FERC granted Southern Company's and other SeTrans' sponsors petition for a declaratory order regarding the governance structure and the selection process for the Independent System Administrator (ISA) of the SeTrans RTO. The FERC also provided guidance on other issues identified in the petition. The SeTrans sponsors announced the selection of ESB International, Ltd. (ESBI) to be the preferred ISA candidate. Should negotiations with this candidate successfully conclude with final agreement among the parties, the SeTrans sponsors intend to seek any state and federal regulatory or other approvals necessary for formation of the SeTrans RTO and the approval of ESBI to serve in the capacity of the SeTrans ISA. The creation of SeTrans is not expected to have a material impact on Southern Company's financial statements; however, the outcome of this matter cannot now be determined.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2002 Annual Report
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 certain aspects of the proposal have been submitted by Southern Company. Any impact of this proposal on Southern Company and its subsidiaries will depend on the form in which final rules may be ultimately adopted; however, Southern Company's revenues, expenses, assets, and liabilities could be adversely affected by changes in the transmission regulatory structure in its regional power market.
Accounting Policies
Critical Policy
Southern Company's significant accounting policies are described in Note 1 to the financial statements. The company's only critical accounting policy involves rate regulation. The operating companies are subject to the provisions of FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of a company's operations is no longer subject to these provisions, the company would be required to write off related regulatory assets and liabilities that are not specifically recoverable and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
New Accounting Standards
Derivatives - -----------
Effective January 2001, Southern Company adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. In October 2002, the Emerging Issues Task Force (EITF) of the FASB announced accounting changes related to energy trading contracts in Issue No. 02-03. In October 2002, Southern Company prospectively adopted the EITF's requirements to reflect the impact of certain energy trading contracts on a net basis. This change had no material impact on the company's income statement. Another change also required certain energy trading contracts to be accounted for on an accrual basis effective January 2003. This change had no impact on Southern Company's current accounting treatment.
Asset Retirement Obligations - ----------------------------
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 establishes 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 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 non-regulated companies 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 "Regulatory Assets and Liabilities" and "Depreciation and Decommissioning."
Guarantees - ----------
In 2002, the FASB issued Interpretation No. 45, Accounting and Disclosure Requirements for Guarantees. This interpretation requires disclosure of certain direct and indirect guarantees as reflected in Note 9 to the financial statements under "Guarantees." Also, the interpretation requires recognition of a liability at inception for certain new or modified guarantees issued after December 31, 2002. The adoption of Interpretation No. 45 in January 2003 did not have a material impact on the consolidated financial statements.
FINANCIAL CONDITION - -------------------
Overview
Southern Company's financial condition continues to remain strong. At December 31, 2002, each of the operating companies were within their allowed range of return on equity after receiving base rate increases during the year. Also, earnings from the competitive generation business and the other business activities made a solid contribution.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2002 Annual Report
Gross property additions to utility plant from continuing operations were $2.7 billion in 2002. The majority of funds needed for gross property additions since 1999 has been provided from operating activities. The Consolidated Statements of Cash Flows provide additional details.
Off-Balance Sheet Financing Arrangements
At December 31, 2002, Southern Company has one financing arrangement that was not required to be recorded on the balance sheet. In May 2001, Mississippi Power began the initial 10-year term of an operating lease agreement signed in 1999 with Escatawpa Funding, Limited Partnership, a special purpose entity, to use a combined-cycle generating facility located at Mississippi Power's Plant Daniel. The facility cost approximately $370 million. The lease provides for a residual value guarantee -- approximately 71 percent of the completion cost -- by Mississippi Power that is due upon termination of the lease in certain circumstances.
Recently, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities. If the Escatawpa financing arrangement is not restructured, this interpretation would require Mississippi Power to consolidate the assets and liabilities associated with Escatawpa by July 2003 and to record a cumulative adjustment to income that is not expected to be material. See Note 9 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 sales, fixed-price physical gas purchases, and agreements covering interest rate swaps and currency swaps. At December 31, 2002, the maximum potential collateral requirements under the electricity sale contracts were approximately $422 million. Generally, collateral may be provided for by a Southern Company guaranty, a letter of credit, or cash. At December 31, 2002, 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, currency exchange rates, and certain 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.
The weighted average rate on variable long-term debt outstanding at December 31, 2002, was 1.9 percent. If Southern Company sustained a 100 basis point change in interest rates for all variable rate long-term debt, the change would affect annualized interest expense by approximately $29 million at December 31, 2002. To further mitigate exposure to interest rates, the company has entered into interest rate swaps that have been designated as cash flow hedges. 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 8 to the financial statements under "Financial Instruments."
Due to cost-based rate regulations, the 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 operating companies and Southern Power enter 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. Southern Company GAS also enters into fixed price contracts for gas purchases to mitigate its exposure to price volatility. Also, the operating companies have implemented fuel-hedging programs at the instruction of their respective public service commissions. Georgia Power's program became effective in January 2003.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2002 Annual Report
The fair value of changes in derivative energy contracts and year-end valuations were as follows at December 31:
Changes in Fair Value - -------------------------------------------------------------- 2002 2001 - -------------------------------------------------------------- (in millions) Contracts beginning of year $ 1.3 $ 1.7 Contracts realized or settled (32.2) (1.4) New contracts at inception - - Changes in valuation techniques - - Current period changes 78.2 1.0 - -------------------------------------------------------------- Contracts end of year $ 47.3 $ 1.3 ==============================================================
Source of Year-End Valuation Prices - -------------------------------------------------------------- Maturity Total --------------------- Fair Value Year 1 1-3 Years - -------------------------------------------------------------- (in millions) Actively quoted $47.3 $53.5 $(6.2) External sources - - - Models and other methods - - - - ------------------------------------------------------------- Contracts end of year $47.3 $53.5 $(6.2) =============================================================
Unrealized gains and losses from mark to market adjustments on contracts related to 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 operating companies' fuel cost recovery clauses. In addition, unrealized 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, 2002, the fair value of derivative energy contracts was reflected in the financial statements as follows:
Amounts - -------------------------------------------------------------- (in millions) Regulatory liabilities, net $37.1 Other comprehensive income 8.7 Net income 1.5 - -------------------------------------------------------------- Total fair value $47.3 ==============================================================
A $5 million loss and $9 million gain were recognized in income in 2002 and 2001, respectively. Southern Company is exposed to market price risk in the event of nonperformance by parties 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 8 to the financial statements under "Financial Instruments."
Capital Structure
During 2002, Southern Company issued $2.7 billion of senior notes and $1.3 billion in trust preferred securities. The issuances were used to refund $1.4 billion of long-term debt and $1.2 billion of trust preferred securities and to finance $575 million of Southern Power's new generating facilities. The remainder was used to reduce short-term debt and fund Southern Company's ongoing construction program. Southern Company also issued 16 million new shares through the company's stock plans and 2 million treasury shares of common stock in 2002. Proceeds of $451 million were used to reduce short-term debt and for capital contributions.
At the close of 2002, the market value of Southern Company's common stock was $28.39 per share, compared with book value of $12.16 per share. The market-to-book value ratio was 233 percent at the end of 2002, compared with 222 percent at year-end 2001.
Capital Requirements for Construction
The construction program of Southern Company is currently estimated to be $2.1 billion for 2003, $2.3 billion for 2004, and $2.4 billion for 2005. 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 4,100 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. Significant construction of transmission and distribution facilities and upgrading of generating plants will also be continuing.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $2.8 billion will be required by the end of 2005 for maturities of long-term debt. Also, the subsidiaries will continue to retire higher-cost debt and preferred stock and replace these obligations with lower-cost capital if market conditions permit.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2002 Annual Report
As a result of requirements by the Nuclear Regulatory Commission, 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 "Depreciation and Nuclear Decommissioning." 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 subsidiaries' respective regulatory commissions.
The capital requirements, lease obligations, purchase commitments, and trust requirements -- discussed in the financial statements -- are as follows:
2003 2004 2005 - ------------------------------------------------------------- (in millions) Senior and other notes $1,639 $ 692 $ 432 Leases -- Capital 11 9 7 Operating 125 114 99 Purchase commitments -- Fuel 2,211 1,735 1,296 Purchased power 116 136 171 Long-term service agreements 50 45 43 Trusts -- Nuclear decommissioning 29 29 29 Postretirement benefits 15 16 34 - -------------------------------------------------------------
Environmental Matters
New Source Review Enforcement 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 the system service company. The complaint alleges violations of the New Source Review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. 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 operating companies a notice of violation related to 10 generating facilities, which includes the five facilities mentioned previously. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation, and to add Gulf Power, Mississippi Power, and Savannah Electric as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal-burning plants constructed or under construction prior to 1978.
The U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and granted the system service company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. 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 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. Also, the EPA refiled its claims against Alabama Power in the U.S. District Court in Alabama. It has not refiled against Gulf Power, Mississippi Power, or the system service company. The Alabama Power, Georgia Power, and Savannah Electric cases have been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA appeal involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA appeal could have a significant adverse impact on Alabama Power and Georgia Power, both companies have been parties to that case as well. In February 2003, the U.S. District Court in Alabama extended the stay of the EPA litigation proceeding in Alabama until the earlier of May 6, 2003 or a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the related litigation involving TVA. On August 21, 2002, the U.S. District Court in Georgia denied the EPA's motion to reopen the Georgia case. The denial was without prejudice to the EPA to refile the motion at a later date, which the EPA has not done at this time.
Southern Company believes that its 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2002 Annual Report
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, a major portion of which is expected to be recovered through existing ratemaking provisions. 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. Compliance was required in two phases -- Phase I, effective in 1995 and Phase II, effective in 2000. Construction expenditures associated with Phase I and Phase II compliance totaled approximately $400 million.
Some of the expenditures required to comply with the Phase II acid rain requirements 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 and Birmingham, Alabama. The states of Alabama and Georgia have adopted regulations that will require additional nitrogen oxide emission reductions from plants in and/or near those nonattainment areas, beginning in May 2003. Seven generating plants in the Atlanta area and two plants in the Birmingham area will be affected. Construction expenditures for compliance with these new rules are currently estimated at approximately $980 million, of which $140 million remains to be spent.
To help bring the remaining nonattainment areas into compliance with 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. However, for Georgia, the EPA must complete a separate rulemaking before the requirements will apply. The EPA proposed a rule for Georgia in 2002 and expects to issue a final rule in 2003. The proposed rule requires compliance by May 1, 2005. Additional construction expenditures for compliance with these new rules are currently estimated at approximately $305 million, of which $295 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 ozone standard unlawful and remanded it to the EPA for further rulemaking. The EPA is expected to propose implementation rules designed to address the court's concerns in 2003 and issue final implementation rules in 2004. The remaining legal challenges to the new standards, which were pending before the U.S. Court of Appeals, District of Columbia Circuit, have been resolved.
The EPA plans to designate areas as attainment or nonattainment with the new eight-hour ozone standard by April 2004, based on air quality data for 2001 through 2003. Several areas within the Southern Company's service area are likely to be designated nonattainment under the new ozone standard. State implementation plans, including new emission control regulations necessary to bring those areas into attainment, could be required as early as 2007. Those state plans 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.
The EPA currently plans to designate areas as attainment or nonattainment with the new fine particulate matter standard by the end of 2004. Those area designations will be based on air quality data collected during 2001 through 2003. Several areas within the company's service area will likely be designated nonattainment under the new particulate matter standard. State implementation plans, including new emission control regulations necessary to bring those areas into attainment, could be required as early as the end of 2007. Those state plans will likely require reductions in sulfur dioxide emissions from power plants. If so, the reductions could be required sometime after 2007. Any additional emission reductions and costs associated with the new fine particulate matter standard cannot be determined at this time.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2002 Annual Report
The EPA has also announced plans to issue a proposed Regional Transport Rule for the fine particulate matter standard by the end of 2003 and to finalize the rule in 2005. This rule would likely require year-round sulfur dioxide and nitrogen oxide emission reductions from power plants as early as 2010. If issued, this rule would likely modify other state implementation plan requirements for attainment of the fine particulate matter standard and the eight-hour ozone standard. It is not possible at this time to determine the effect such a rule would have on the company.
Further reductions in sulfur dioxide 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 State Implementation Plans in 2007 and 2008 that contain emission reduction strategies for achieving progress toward the visibility improvement goal. In 2002, however, the U.S. Court of Appeals, District of Columbia Circuit, vacated and remanded the BART provisions of the federal Regional Haze rules to the EPA for further rulemaking. Because new BART rules have not been developed and state visibility assessments 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. Four of Southern Company's operating companies -- Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric -- will be applying for renewal of their Title V operating permits between 2003 and 2005, and a number of the 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, which could indicate a need for improved particulate matter controls at affected facilities. Because the plans are still in the early stages of development, the company cannot determine the extent to which improved controls could be required or the costs associated with any necessary improvements. Actual ongoing monitoring costs are expensed as incurred and are not material for any period presented.
In December 2000, having completed its utility studies for mercury and other hazardous air pollutants (HAPS), the EPA issued a determination that an emission control program for mercury and, perhaps, other HAPS is warranted. The program is being developed under the Maximum Achievable Control Technology provisions of the Clean Air Act. The EPA currently plans to issue proposed rules regulating mercury emissions from electric utility boilers by the end of 2003, and those regulations are scheduled to be finalized by the end of 2004. Compliance could be required as early as 2007. Because the rules have not yet been proposed, the costs associated with compliance cannot be determined at this time.
In December 2002, the EPA issued final and proposed revisions to the New Source Review program under the Clean Air Act. In February 2003, several northeastern states petitioned the D.C. Circuit Court for a stay of the final rules. The proposed rules are open to public comment and may be revised before being finalized by the EPA. If fully implemented, these proposed and final regulations could affect the applicability of the New Source Review provisions to activities at the company's facilities. In any event, any final regulations must be adopted by the states in the company's service area in order to apply to the company's facilities. The effect of these proposed and final rules cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent emissions limitations have been proposed. Three of these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2002, and the Clean Air Planning Act of 2002, proposed to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills also proposed to limit emissions of carbon dioxide. None of these bills were enacted into law in the last Congress. Similar bills have been, and are anticipated to be, introduced this year. The Bush Administration's Clear Skies Act was recently reintroduced, and President Bush has stated that it will be a high priority for the administration. Other bills already introduced include the Climate Stewardship Act of 2003, which proposes capping greenhouse gas emissions. The cost impacts of such legislation would depend upon the specific requirements enacted.
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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2002 Annual Report
ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation and has instead announced a new voluntary climate initiative 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. Because this initiative is still under development, it is not possible to determine the effect on the company at this time.
Southern Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous 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. Southern Company expensed $4 million, $1 million, and $4 million in 2002, 2001, and 2000, respectively. The subsidiaries may be liable for a portion or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements for information regarding Georgia Power's potentially responsible party status at sites in Georgia.
Under the Clean Water Act, the EPA is developing new rules aimed at reducing impingement and entrainment of fish and fish larvae at cooling water intake structures that will require numerous biological studies and, perhaps, retrofits to some intake structures at existing power plants. The new rule was proposed in February 2002 and will be finalized by August 2004. The impact of any new standards will depend on the development and implementation of applicable regulations.
Also, 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 discharging 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.
The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including limits on pollutant discharges to impaired waters, hazardous waste disposal requirements, and other regulatory matters. The impact of any new standards 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.
Compliance with possible additional federal or state legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could also significantly affect Southern Company. The impact of any new legislation, or changes to existing legislation, could affect many areas of Southern Company's operations. The full impact of any such changes cannot, however, be determined at this time.
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 2003 - -- 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 2003. Equity capital can be provided from any combination of the company's stock plans, private placements, or public offerings.
The 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 internal sources. 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 trust 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Company and Subsidiary Companies 2002 Annual Report
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. Subsequent to December 31, 2002, the operating companies have issued $545 million of new securities with the proceeds being used primarily to retire current maturities and to reduce short-term debt. An additional $414 million of securities has been issued to retire long-term debt and for other corporate purposes.
To meet short-term cash needs and contingencies, Southern Company has various internal and external sources of liquidity. At the beginning of 2003, Southern Company and its subsidiaries had approximately $273 million of cash and cash equivalents and $3.9 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 to meet liquidity needs. Cash flows from operating activities were $2.8 billion in 2002 and $2.4 billion in both 2001 and 2000.
Bank credit arrangements are as follows:
Expires ---------------------------- Total Unused 2003 & Beyond - -------------------------------------------------------------- (in millions) $4,261 $3,856 $2,981 $875 - --------------------------------------------------------------
Approximately $2.6 billion of the credit facilities expiring in 2003 allow for the execution of term loans for an additional two-year period.
See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information.
Cautionary Statement Regarding Forward-Looking Information
Southern Company's 2002 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 expenditures and Southern Company's projections for energy sales and its goals for future generating capacity, dividend payout ratio, equity 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 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 and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations; current and future litigation, including the pending EPA civil actions against certain Southern Company subsidiaries; the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate; the impact of fluctuations in commodity prices, interest rates, and customer demand; state and federal rate regulations; political, legal, and economic conditions and developments in the United States; the performance of projects undertaken by the non-traditional business and the success of efforts to invest in and develop new opportunities; internal restructuring or other restructuring options that may be pursued; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries; the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due; the effects of, and changes in, economic conditions in the areas in which Southern Company's subsidiaries operate, including the current soft economy; the direct or indirect effects on Southern Company's business resulting from the terrorist incidents on September 11, 2001, or any similar such incidents or responses to such incidents; financial market conditions and the results of financing efforts; the timing and acceptance of Southern Company's new product and service offerings; the ability of Southern Company to obtain additional generating capacity at competitive prices; weather and other natural phenomena; and other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed from time to time by Southern Company with the Securities and Exchange Commission.
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NOTES TO FINANCIAL STATEMENTS Southern Company and Subsidiary Companies 2002 Annual Report
1. SUMMARRY OF SIGNIFICANT ACCOUNTING POLICIES
General
Southern Company is the parent company of five operating companies, Southern Power Company (Southern Power), a system service company, 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 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 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. The system service company provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the 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, which began operation in August 2002, is a competitive retail natural gas marketer serving communities in Georgia. Southern Holdings is an intermediate holding subsidiary for Southern Company's investments in leveraged leases, alternative fuel products, and an energy services business. Southern Nuclear 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, see Note 11.
The financial statements reflect Southern Company's investments in the subsidiaries on a consolidated basis. 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 operating companies and Southern Power are subject to regulation by the FERC, and the 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.
Regulatory Assets and Liabilities
The 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 the following:
2002 2001 - -------------------------------------------------------------- (in millions) Deferred income tax charges $ 898 $ 924 Premium on reacquired debt 313 280 Department of Energy assessments 33 39 Vacation pay 99 95 Postretirement benefits 25 28 Deferred income tax credits (450) (500) Accelerated cost recovery (229) (344) Storm damage reserves (38) (34) Fuel-hedging assets - 9 Fuel-hedging liabilities (38) (2) Other assets 188 164 Other liabilities (91) (13) - -------------------------------------------------------------- Total $ 710 $ 646 ==============================================================
See "Depreciation and Nuclear Decommissioning" in this note for information regarding significant regulatory assets and liabilities created as a result of the January 1, 2003, adoption of FASB Statement No. 143, Accounting for Asset Retirement Obligations.
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
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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, including plant, and write down the assets, if impaired, to their fair value. All regulatory assets and liabilities are reflected in rates.
Revenues and Fuel Costs
Energy revenues are recognized as services are rendered. Capacity revenues are generally recognized on a levelized basis over the appropriate contract periods. 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 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 fuel. Total charges for nuclear fuel included in fuel expense amounted to $134 million in 2002, $133 million in 2001, and $136 million in 2000. 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 2014. At Plant Hatch, an on-site dry storage facility became operational in 2000. Sufficient dry storage capacity is believed to be available to continue dry storage operations at Plant Hatch through the life of the plant. Procurement of on-site dry storage capacity at Plant Farley is in progress, with the intent to place the capacity in operation in 2005. Procurement of on-site dry storage capacity 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 interests -- estimate their respective remaining liability at December 31, 2002, under this law to be approximately $17 million and $13 million. These obligations are recorded in other deferred credits in the Consolidated Balance Sheets.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.2 percent in 2002 and 3.4 percent a year in 2001 and 2000. 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 costs of decommissioning nuclear facilities and removal of other facilities. 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 January 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 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 cost must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life.
The cumulative effect adjustment to net income resulting from the adoption of Statement No. 143 was immaterial. The operating companies expect to receive
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accounting orders from their respective public service commissions to defer the transition adjustment; therefore, Southern Company recorded a related regulatory liability of $47 million to reflect the operating companies' regulatory treatment of these costs under Statement No. 71. The initial Statement No. 143 liability Southern Company recognized was $778 million, of which $644 million was removed from the accumulated depreciation reserve. The amount capitalized to property, plant, and equipment was $181 million.
The liability recognized to retire long-lived assets primarily relates to the company's nuclear facilities, which include Alabama Power's Plant Farley and Georgia Power's ownership interests in plants Hatch and Vogtle. In addition, the operating companies have retirement obligations related to various landfill sites, ash ponds, and underground storage tanks. Southern Company has also identified retirement obligations related to certain transmission and distribution facilities. However, a liability for the removal of these transmission and distribution assets will not be recorded because no reasonable estimate can be made regarding the timing of any related retirements. The operating companies will continue to recognize in the income statement their ultimate 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 will be recognized as either a regulatory asset or liability. It is estimated that this annual difference will be approximately $27 million. Management believes actual asset removal costs will be recoverable in rates over time.
Statement No. 143 does not permit non-regulated companies to continue accruing future retirement costs for long-lived assets that they do not have a legal obligation to retire. However, in accordance with the regulatory treatment of these costs, the operating companies will continue to recognize the removal costs for these other obligations in their depreciation rates. As of January 1, 2003, the amount included in the accumulated depreciation reserve that represents a regulatory liability for these costs was $1.23 billion.
Georgia Power recorded accelerated depreciation and amortization amounting to $91 million in 2001 and $135 million in 2000. 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. See Note 3 under "Georgia Power Retail Rate Orders" for additional information.
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. 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, and ultimate cost is the estimate to decommission a specific facility as of its retirement date. The estimated costs of decommissioning -- both site study costs and ultimate costs -- based on the most current study as of December 31, 2002 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 1998 2000 2000 Decommissioning periods: Beginning year 2017 2014 2027 Completion year 2031 2042 2045 - -------------------------------------------------------------- (in millions) Site study costs: Radiated structures $629 $486 $420 Non-radiated structures 60 37 48 - -------------------------------------------------------------- Total $689 $523 $468 ============================================================== (in millions) Ultimate costs: Radiated structures $1,868 $1,004 $1,468 Non-radiated structures 178 79 166 - -------------------------------------------------------------- Total $2,046 $1,083 $1,634 ==============================================================
Significant assumptions: Inflation rate 4.5% 4.7% 4.7% Trust earning rate 7.0 6.5 6.5 - --------------------------------------------------------------
The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary
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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 2002 and fund balances were as follows:
Plant Plant Plant Farley Hatch Vogtle - -------------------------------------------------------------- (in millions) Amount expensed in 2002 $ 18 $ 7 $ 2 Accumulated provisions: External trust funds, at fair value $292 $219 $128 Internal reserves 34 7 4 - -------------------------------------------------------------- Total $326 $226 $132 ==============================================================
Alabama Power's decommissioning costs for ratemaking are based on the site study. Effective January 1, 2002, the Georgia Public Service Commission (GPSC) decreased Georgia Power's annual provision for decommissioning expenses 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. The ultimate costs associated with the 2000 NRC minimum funding requirements are $823 million and $1.03 billion for plants Hatch and Vogtle, 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 would permit the operation of units 1 and 2 until 2034 and 2038, respectively. Decommissioning costs will not reflect the license extension until a new site study is complete in 2003 and the GPSC issues a new rate order, which is not expected until December 2004. Alabama Power has notified the NRC that it plans to submit an application in September 2003 to extend the operating license for Plant Farley for an additional 20 years.
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.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized
In accordance with regulatory treatment, the 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 operating companies' retail rates is capitalized in accordance with standard interest capitalization requirements.
Cash payments for interest totaled $544 million, $624 million, and $802 million in 2002, 2001, and 2000, respectively, net of amounts capitalized of $59 million, $57 million, and $44 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 recent 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.
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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 depreciation and amortization and for interest on long-term debt related to these investments.
Southern Company's net investment in leveraged leases consists of the following at December 31:
2002 2001 - -------------------------------------------------------------- (in millions) Net rentals receivable $1,507 $1,430 Unearned income (716) (775) - -------------------------------------------------------------- Investment in leveraged leases 791 655 Deferred taxes arising from leveraged leases (260) (193) - -------------------------------------------------------------- Net investment in leveraged leases $ 531 $ 462 ==============================================================
A summary of the components of income from leveraged leases is as follows:
2002 2001 2000 - -------------------------------------------------------------- (in millions) Pretax leveraged lease income $58 $59 $61 Income tax expense 21 21 21 - --------------------------------------------------------------- Net leveraged lease income $37 $38 $40 ===============================================================
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 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 reevaluated when circumstances or events change.
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.
Comprehensive Income
Comprehensive income -- consisting 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 -- is presented in the consolidated financial statements. Comprehensive income from discontinued operations also includes foreign currency translation adjustments, net of income taxes. 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.
Financial Instruments
Southern Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, foreign currency exchange 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 are derivatives. However, in many cases, these
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contracts qualify as normal purchases and sales and are accounted for under the accrual method. Other 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. Contracts that do not qualify for the normal purchase and sale exception and that do not meet the hedge requirements 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.
Other Southern Company 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, 2002 $10,191 $10,475 At December 31, 2001 8,634 8,693 Capital and preferred securities: At December 31, 2002 2,420 2,498 At December 31, 2001 2,276 2,282 - --------------------------------------------------------------
The fair values for long-term debt and capital and preferred securities were based on either closing market price or closing price of comparable instruments.
2. RETIREMENT BENEFITS
Southern Company has a defined benefit, trusteed, pension plan that covers substantially all employees. Southern Company also provides certain non-qualified benefit plans for a selected group of management and highly compensated employees. Also, Southern Company provides certain medical care and life insurance benefits for retired employees. The operating companies fund trusts to the extent required by their respective regulatory commissions. In late 2000, as well as in 2002, Southern Company adopted several pension and postretirement benefit plan changes that had the effect of increasing benefits to both current and future retirees.
Plan assets consist primarily of domestic and international equities, global fixed income securities, real estate, and private equity investments. The measurement date for plan assets and obligations is September 30 for each year.
Pension Plan
Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows: Projected Benefit Obligations ------------------- 2002 2001 - -------------------------------------------------------------- (in millions) Balance at beginning of year $3,760 $3,397 Service cost 109 104 Interest cost 277 260 Benefits paid (184) (176) Plan amendments 88 173 Actuarial (gain) loss 44 2 - -------------------------------------------------------------- Balance at end of year $4,094 $3,760 ==============================================================
Plan Assets ----------------- 2002 2001 - -------------------------------------------------------------- (in millions) Balance at beginning of year $5,109 $6,157 Actual return on plan assets (343) (889) Benefits paid (166) (159) - -------------------------------------------------------------- Balance at end of year $4,600 $5,109 ==============================================================
The accrued pension costs recognized in the Consolidated Balance Sheets were as follows:
2002 2001 - -------------------------------------------------------------- (in millions) Funded status $ 506 $ 1,349 Unrecognized transition obligation (39) (51) Unrecognized prior service cost 334 269 Unrecognized net gain (loss) (115) (1,020) - -------------------------------------------------------------- Prepaid asset, net 686 547 Portion included in benefit obligations 100 94 - -------------------------------------------------------------- Total prepaid assets recognized in the Consolidated Balance Sheets $ 786 $ 641 ==============================================================
In 2002 and 2001, amounts recognized in the Consolidated Balance Sheets for accumulated other comprehensive income and intangible assets were $49 million and $35 million and $0 million and $33 million, respectively.
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Components of the pension plan's net periodic cost were as follows:
2002 2001 2000 - ------------------------------------------------------------- (in millions) Service cost $ 109 $ 104 $ 96 Interest cost 277 260 239 Expected return on plan assets (449) (423) (384) Recognized net gain (65) (73) (62) Net amortization 11 8 - - ------------------------------------------------------------- Net pension cost (income) $(117) $ (124) $(111) =============================================================
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 ------------------- 2002 2001 - -------------------------------------------------------------- (in millions) Balance at beginning of year $1,239 $1,052 Service cost 21 22 Interest cost 91 88 Benefits paid (62) (54) Plan amendments - 186 Actuarial (gain) loss 172 (55) - -------------------------------------------------------------- Balance at end of year $1,461 $1,239 ==============================================================
Plan Assets ------------------ 2002 2001 - -------------------------------------------------------------- (in millions) Balance at beginning of year $425 $459 Actual return on plan assets (34) (59) Employer contributions 88 79 Benefits paid (62) (54) - -------------------------------------------------------------- Balance at end of year $417 $425 ==============================================================
The accrued postretirement costs recognized in the Consolidated Balance Sheets were as follows:
2002 2001 - -------------------------------------------------------------- (in millions) Funded status $(1,043) $(814) Unrecognized transition obligation 159 174 Unrecognized prior service cost 225 239 Unrecognized net loss (gain) 239 (9) Fourth quarter contributions 51 41 - -------------------------------------------------------------- Accrued liability recognized in the Consolidated Balance Sheets $ (369) $(369) ==============================================================
Components of the postretirement plan's net periodic cost were as follows:
2002 2001 2000 - ------------------------------------------------------------- (in millions) Service cost $ 21 $ 22 $ 18 Interest cost 91 88 76 Expected return on plan assets (42) (40) (34) Net amortization 29 26 18 - ------------------------------------------------------------- Net postretirement cost $ 99 $ 96 $ 78 =============================================================
The weighted average rates assumed in the actuarial calculations for both the pension plan and postretirement benefits plan were:
2002 2001 2000 - -------------------------------------------------------------- Discount 6.5% 7.5% 7.5% Annual salary increase 4.0 5.0 5.0 Long-term return on plan assets 8.5 8.5 8.5 - --------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 8.75 percent for 2002, 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, 2002, as follows:
1 Percent 1 Percent Increase Decrease - -------------------------------------------------------------- (in millions) Benefit obligation $122 $108 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 2002, 2001, and 2000 were $53 million, $51 million, and $49 million, respectively.
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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. Southern Company's business activities are also 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 currently filed against Southern Company and its subsidiaries cannot be predicted at this time; however, after consultation with legal counsel, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on Southern Company's financial statements.
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, 2002, 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, 2002, 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 Enforcement Actions
In November 1999, the EPA brought a civil action in U.S. District Court in Georgia against Alabama Power, Georgia Power, and the system service company. The complaint alleges violations of the New Source Review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. 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 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.
The EPA concurrently issued to the operating companies a notice of violation related to 10 generating facilities, which includes the five facilities mentioned previously. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation and to add Gulf Power, Mississippi Power, and Savannah Electric as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal-burning plants constructed or under construction prior to 1978. The U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and granted the system service company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. 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 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. Also, the EPA refiled its claims against Alabama Power in the U.S. District Court in Alabama. It has not refiled against Gulf Power, Mississippi Power, or the system service company.
The Alabama Power, Georgia Power, and Savannah Electric cases have been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA appeal involves many of the same legal issues raised by the actions against Alabama
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Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA appeal could have a significant adverse impact on Alabama Power and Georgia Power, both companies have been parties to that case as well. In February 2003, the U.S. District Court in Alabama extended the stay of the EPA litigation proceeding in Alabama until the earlier of May 6, 2003, or a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the related litigation involving TVA. On August 21, 2002, the U.S. District Court in Georgia denied the EPA's motion to reopen the Georgia case. The denial was without prejudice to the EPA to refile the motion at a later date, which the EPA has not done at this time.
Southern Company believes that its operating companies complied with applicable laws and the EPA's regulations and interpretations in effect at the time the work in question took place. 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 U.S. District Court in Georgia against Georgia Power for alleged violations of the Clean Air Act 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 January 27, 2003, Georgia Power filed a response to the complaint. Georgia Power also filed a motion to dismiss the allegations regarding emission offsets and hazardous air pollutants. 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.
Mobile Energy Services' Petition for Bankruptcy
Mobile Energy Services Holdings (MESH), a subsidiary of Southern Company, 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 relief in the U.S. Bankruptcy Court. This action was in response to Kimberly-Clark Tissue Company's announcement in May 1998 of plans to close its pulp mill, which had historically provided 50 percent of MESH's revenues.
As a result of the bankruptcy filing, Southern Company has written off its entire investment in MESH, including a $10 million after-tax write down in 2000. At December 31, 2002, MESH had senior debt outstanding of $139 million of first mortgage bonds and $53 million related to tax-exempt bonds. In connection with the bond financings, in lieu of funding debt service and maintenance reserve accounts, Southern Company provided and has subsequently paid certain limited guarantees totaling $41 million. Southern Company continues to have a guarantee outstanding of certain potential environmental obligations of MESH and an obligation under certain circumstances to fund a maintenance reserve account for the benefit of the owners of the pulp and paper complex that together represent a maximum contingent liability of $19 million at December 31, 2002. Mirant, formerly a subsidiary of Southern Company, agreed to indemnify Southern Company for any amounts required to be paid under such guarantees.
In August 2000, MESH filed a proposed plan of reorganization with the U.S. Bankruptcy Court. The proposed plan of reorganization was most recently amended on December 13, 2001. Southern Company expects that approval of a plan of reorganization would result in a termination of Southern Company's ownership interest in MESH but would not affect Southern Company's continuing guarantee obligations discussed earlier. The final outcome of this matter cannot now be determined.
California Electricity Markets Litigation
Prior to the spin off of Mirant, Southern Company was named as a defendant in two lawsuits filed in the superior courts of California alleging that certain owners of electric generation facilities in California, including Southern Company, engaged in various unlawful and anticompetitive acts that served to manipulate wholesale power markets and inflate wholesale electricity prices in California with the result, as alleged in one lawsuit, that customers paid
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approximately $4 billion more for electricity than they otherwise would have. Both lawsuits sought an award of treble damages, as well as other injunctive and equitable relief. In the fall of 2001, the plaintiffs voluntarily dismissed Southern Company without prejudice from the two lawsuits in which it had been named as a defendant. Prior to being dismissed, Southern Company had notified Mirant of its claim for indemnification for costs associated with the lawsuits under the terms of the master separation agreement that governs the spin off of Mirant. Mirant had undertaken the defense of the lawsuits. Plaintiffs would not be barred by their own dismissal from naming Southern Company in some future lawsuit, but management believes that the likelihood of Southern Company having to pay damages in any such lawsuit is remote.
California Electricity Markets Investigation
Southern Company has received a subpoena to provide information to a federal grand jury in the Northern District of California. The subpoena covers a number of broad areas, including specific information regarding electricity production and sales activities in California. Southern Company's former subsidiary, 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 is fully cooperating in the investigation.
Mirant Securities Litigation
In November 2002, Southern Company, along with certain former and current senior officers of Southern Company and 12 underwriters of Mirant's initial public offering, were added as defendants in a class action lawsuit that several Mirant shareholders originally filed against Mirant and certain Mirant officers in May 2002. The original lawsuit against Mirant and its officers 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 November 2002 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. For more information, see Note 11. The lawsuit purports to include persons who acquired Mirant securities on the open market or pursuant to an offering between September 26, 2000 and September 5, 2002. The amended complaint does not allege any improper trading and marketing activity, accounting errors, or material misstatements or omissions on the part of Southern Company but seeks to impose liability on Southern Company based on allegations that Southern Company was a "control person" as to Mirant. On February 14, 2003, Southern Company filed a motion seeking to dismiss all claims against the company. However, 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 the system service company 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 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. The parties await the district court's ruling on the seven motions for summary judgment. The final outcome of the case cannot now be determined.
Right of Way Litigation
In 2002, certain subsidiaries of Southern Company, including Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, and Southern Telecom (collectively, defendants), were named as defendants in numerous lawsuits brought by landowners 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
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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. Defendants believe 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.
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. Both increases and decreases have been placed into effect since the adoption of these rates. 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. The 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.
Georgia Power Retail Rate Orders
In December 2001, the GPSC approved a three-year retail rate order for Georgia Power ending December 31, 2004. Under the terms of the order, earnings will be 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. Retail rates were decreased by $118 million effective January 1, 2002.
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 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 has been credited to a regulatory liability account as mandated by the GPSC.
Under the rate order, the accumulated accelerated amortization and the interest will be amortized equally over three years as a credit to expense beginning in 2002. Effective January 1, 2002, Georgia Power discontinued recording accelerated depreciation and amortization. Georgia Power may not file for a general base rate increase unless its projected retail return on common equity falls below 10 percent. 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.
In 2000 and 1999, Georgia Power recorded $44 million and $79 million, respectively, of revenue subject to refund for estimated earnings above 12.5 percent retail return on common equity. Those refunds were made to customers in 2001 and 2000, respectively.
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 (FP&L), and Jacksonville Electric Authority (JEA). In addition, Georgia Power has joint ownership agreements with OPC for the Rocky Mountain facilities and with Florida Power Corporation (FPC) 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. The unit is scheduled to go into commercial operation in October 2003.
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At December 31, 2002, 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% $3,267 $1,779 Plant Hatch (nuclear) 50.1 884 665 Plant Miller (coal) Units 1 and 2 91.8 760 341 Plant Scherer (coal) Units 1 and 2 8.4 113 58 Plant Wansley (coal) 53.5 305 156 Rocky Mountain (pumped storage) 25.4 169 82 Intercession City (combustion turbine) 33.3 12 1 Plant Stanton (combined cycle) Unit A 65.0 128 - - --------------------------------------------------------------
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. LONG-TERM POWER SALES AGREEMENTS
The operating companies have long-term contractual agreements for the sale of capacity to certain non-affiliated utilities located outside the system's service area. These agreements are firm and are related to specific generating units. Because the energy is generally provided at cost under these agreements, profitability is primarily affected by capacity revenues.
Unit power from specific generating plants is currently being sold to FP&L, FPC, and JEA. Under these agreements, approximately 1,500 megawatts of capacity is scheduled to be sold annually unless reduced by FP&L, FPC, and JEA for the periods after 2002 with a minimum of three years' notice -- until the expiration of the contracts in 2010. Capacity revenues from unit power sales amounted to $175 million in 2002, $170 million in 2001, and $177 million in 2000.
Southern Power and Mississippi Power have contractual agreements with non-affiliated companies for the sale of capacity from certain generating units. These capacity revenues amounted to $65 million in 2002, $53 million in 2001, and $20 million in 2000. These amounts are included in sales for resale in the income statement. Future capacity revenues as of December 31, 2002, are as follows:
Year Amounts - ---- ------------ (in millions) 2003 $ 73 2004 96 2005 148 2006 178 2007 177 2008 and thereafter 1,396 - -------------------------------------------------------------- Total $2,068 ==============================================================
Included in the amounts above are capacity revenues related to contracts with Dynegy Inc. (Dynegy) of approximately $34 million through May 2005, $64 million from June 2005 through May 2011, and $42 million from June 2011 through May 2030. As a result of Dynegy's liquidity problems, it has provided letters of credit totaling $96 million that can be drawn in the event of a default under the purchase power agreements or the failure to renew the letters of credit prior to expiration in April 2003.
6. INCOME TAXES
At December 31, 2002, the tax-related regulatory assets and liabilities were $898 million and $450 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. The following tables and disclosures exclude discontinued operations.
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Details of income tax provisions are as follows:
2002 2001 2000 - -------------------------------------------------------------- (in millions) Total provision for income taxes: Federal -- Current $284 $477 $421 Deferred 167 (10) 95 - -------------------------------------------------------------- 451 467 516 - -------------------------------------------------------------- State -- Current 64 103 71 Deferred 13 (12) 1 - -------------------------------------------------------------- 77 91 72 - -------------------------------------------------------------- Total $528 $558 $588 ==============================================================
Net cash payments for income taxes related to continuing operations in 2002, 2001, and 2000 were $372 million, $558 million, and $581 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:
2002 2001 - -------------------------------------------------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $3,364 $3,222 Property basis differences 1,011 1,059 Other 840 739 - -------------------------------------------------------------- Total 5,215 5,020 - -------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 111 116 Other property basis differences 185 178 Deferred costs 188 234 Pension and other benefits 146 123 Other 384 304 - -------------------------------------------------------------- Total 1,014 955 - -------------------------------------------------------------- Total deferred tax liabilities, net 4,201 4,065 Portion included in current assets (liabilities), net 1 23 Deferred state tax assets 12 9 - -------------------------------------------------------------- Accumulated deferred income taxes in the Consolidated Balance Sheets $4,214 $4,097 ==============================================================
In addition, at December 31, 2002, Southern Company had available state of Georgia net operating loss carryforward deductions totaling $779 million, which could result in net state income tax benefits of $30 million, if utilized. Less than $1 million of such deductions will expire by 2007; the remainder will expire between 2008 and 2022. During 2002, Southern Company realized $14 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 $27 million in 2002 and $30 million a year in 2001 and 2000. At December 31, 2002, 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:
2002 2001 2000 - -------------------------------------------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 2.7 3.7 3.4 Alternative fuel tax credits (5.8) (4.2) (1.3) Employee stock plans dividend deduction (2.9) - - Non-deductible book depreciation 1.3 1.7 1.7 Difference in prior years' deferred and current tax rate (1.0) (1.1) (1.3) Other (0.9) (2.2) (0.8) - -------------------------------------------------------------- Effective income tax rate 28.4% 32.9% 36.7% ==============================================================
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 Internal Revenue Service 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.
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7. COMMON STOCK
Stock Issued and Repurchased
In 2002, Southern Company raised $378 million from the issuance of 16 million new common shares under the company's various stock plans. Southern Company issued 2 million, 17 million, and 5 million treasury shares of common stock in 2002, 2001, and 2000, respectively, through various company stock plans. Proceeds from the issuance of treasury stock were $56 million in 2002, $395 million in 2001, and $140 million in 2000.
In April 1999, Southern Company's Board of Directors approved the repurchase of up to 50 million shares of Southern Company's common stock over a two-year period through open market or privately negotiated transactions. Under this program, 50 million shares were repurchased by February 2000 at an average price of $25.53 per share.
Shares Reserved
At December 31, 2002, a total of 42 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, 2002, 5,878 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 in accordance with the plan. Stock option data for the plan has been adjusted to reflect the Mirant spin off. Activity in 2001 and 2002 for the plan is summarized below:
Shares Average Subject Option Price To Option Per Share - -------------------------------------------------------------- Balance at December 31, 1999 13,419,978 $14.97 Options granted 11,042,626 14.67 Options canceled (335,282) 14.87 Options exercised (1,560,695) 13.65 - -------------------------------------------------------------- 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 (103,295) 19.64 Options exercised (4,892,354) 15.16 - -------------------------------------------------------------- Balance at December 31, 2002 32,675,731 $19.72 ==============================================================
Shares reserved for future grants: At December 31, 2000 43,955,368 At December 31, 2001 54,795,653 At December 31, 2002 46,788,994 - -------------------------------------------------------------- Options exercisable: At December 31, 2000 9,354,705 At December 31, 2001 11,965,858 At December 31, 2002 15,463,414 - --------------------------------------------------------------
The following table summarizes information about options outstanding at December 31, 2002:
Dollar Price Range of Options - -------------------------------------------------------------- 11-15 15-20 20-25 - -------------------------------------------------------------- Outstanding: Shares (in thousands) 8,149 11,635 12,892 Average remaining life (in years) 6.1 6.5 8.4 Average exercise price $14.53 $18.40 $24.20 Exerciseable: Shares (in thousands) 5,830 7,186 2,448 Average exercise price $14.47 $17.99 $22.88 - --------------------------------------------------------------
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The estimated fair values of stock options granted in 2002, 2001, and 2000 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:
2002 2001 2000 - --------------------------------------------------------------- Interest rate 2.8% 4.8% 6.7% Average expected life of stock options (in years) 4.3 4.3 4.0 Expected volatility of common stock 26.3% 25.4% 20.9% Expected annual dividends on common stock $1.37 $1.34 $1.34 Weighted average fair value of stock options granted $3.37 $2.82 $3.36 - ---------------------------------------------------------------
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) $1,318 $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 Net income (in millions) $994 $984 Earnings per share (dollars): Basic $1.52 $1.51 Diluted $1.52 $1.51 - --------------------------------------------------------------
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 ------------------------------- 2002 2001 2000 - -------------------------------------------------------------- (in thousands) As reported shares 708,161 689,352 653,087 Effect of options 5,409 4,191 1,018 - -------------------------------------------------------------- Diluted shares 713,570 693,543 654,105 ==============================================================
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2002, consolidated retained earnings included $3.6 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.
8. FINANCING
Capital and Preferred Securities
Company or subsidiary obligated mandatorily redeemable capital and preferred securities have been issued by special purpose financing entities of Southern Company and its subsidiaries. Substantially all the assets of these special financing entities are junior subordinated notes issued by the related company seeking financing. Each of these companies considers that the mechanisms and obligations relating to the capital or preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective special financing entities' payment obligations with respect to the capital or preferred securities. At December 31, 2002, capital securities of $400 million and preferred securities of $2.0 billion were outstanding and recognized in the Consolidated Balance Sheets. Southern Company guarantees the notes related to $950 million of capital or preferred securities issued on its behalf.
Long-Term Debt 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:
2002 2001 - -------------------------------------------------------------- (in millions) First mortgage bond maturities and redemptions $ 33 $ 7 Pollution control bonds 1 8 Capitalized leases 11 4 Senior notes 1,552 380 Other long-term debt 42 30 - -------------------------------------------------------------- Total $1,639 $429 ==============================================================
Debt redemptions and/or serial maturities through 2007 applicable to total long-term debt are as follows: $1.6 billion in 2003; $692 million in 2004; $432 million in 2005; $228 million in 2006; and $519 million in 2007.
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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 operating companies, constitute a direct first lien on substantially all of the operating companies' respective fixed property and franchises. Georgia Power discharged its mortgage in early 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 2003, unused credit arrangements with banks totaled $3.9 billion, of which $3.0 billion expires during 2003, $860 million expires during 2004, and $15 million expires during 2005. The following table outlines the credit arrangements by company:
Amount of Credit -------------------------------------- Expires ---------------- 2004 & Company Total Unused 2003 beyond - ------- -------------------------------------- (in millions) Alabama Power $ 923 $ 923 $ 533 $390 Georgia Power 1,175 1,175 1,175 - Gulf Power 66 66 66 - Mississippi Power 97 97 97 - Savannah Electric 80 55 40 15 Southern Company 1,000 1,000 1,000 - Southern Power 850 470 - 470 Other 70 70 70 - - -------------------------------------------------------------- Total $4,261 $3,856 $2,981 $875 ==============================================================
Approximately $2.6 billion of the credit facilities expiring in 2003 allow the execution of term loans for an additional two-year period. 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 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 $3.9 billion of unused credit arrangements is $3.4 billion of syndicated credit arrangements that require the payment of agent fees.
Most of Southern Company's and the operating companies' credit arrangements with banks have covenants that limit debt levels to 65 percent of total capitalization. For Southern Power, the debt level is 60 percent, excluding intercompany loans. Exceeding these debt levels would result in a default under the credit arrangements. 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 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 if triggered would require prepayment of debt related to projects financed under the credit arrangement that are not complete. Southern Company and its subsidiaries are currently in compliance with all such covenants. Borrowings under certain operating companies' unused credit arrangements totaling $159 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 $3.9 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, 2002 was $941 million.
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Southern Company, the operating companies, and Southern Power borrow through commercial paper programs that have the liquidity support of committed bank credit arrangements. In addition, the companies from time to time borrow under uncommitted lines of credit with banks and through extendible commercial note programs. As of December 31, 2002, the amount outstanding was $20 million under these lines and $31 million in extendible commercial notes. The amount of commercial paper outstanding at December 31, 2002 and December 31, 2001, was $858 million and $1.8 billion, respectively. Commercial paper is included in notes payable on the Consolidated Balance Sheets.
Financial Instruments
Southern Company has firm purchase commitments for equipment that require payment in euros. As a hedge against fluctuations in the exchange rate for euros, the company entered into forward currency swaps. The total notional amount is 6 million euros maturing in 2003. At December 31, 2002, the unrealized gain on these swaps was $1 million.
Southern Company and certain subsidiaries enter into interest rate swaps to hedge exposure to interest rate changes. Swaps related to fixed rate securities are accounted for as fair value hedges. Swaps related to variable rate securities or forecasted transactions are accounted for as cash flow hedges. The swaps are generally structured to mirror the terms of the hedged debt instruments; therefore, no material ineffectiveness has been recorded in earnings. The gain or loss in fair value for cash flow hedges is recorded in other comprehensive income and will be recognized in earnings over the life of the hedged items.
At December 31, 2002, Southern Company had $2.8 billion notional amount of interest rate swaps outstanding with net deferred losses of $52 million as follows:
Fair Value Hedges Fixed Variable Fair Rate Rate Notional Value Company Maturity Received Paid Amount Gain - ------------------------------------------ ----------------- (in millions) Southern Company 2007 5.30% 1.53% $400 $39 - --------------------------------------------------------------
Cash Flow Hedges Weighted Average -------------------- Variable Fixed Fair Rate Rate Notional Value Company Maturity Received Paid Amount (Loss) - ------------------------------------------ ---------------- (in millions) Southern Company 2003 1.74% 3.20% $200 $ (2) 2004 1.74 3.20 200 (4) Alabama Power 2003 1.95 3.02 350 (5) Alabama Power 2004 1.43 1.63 486 (2) Alabama Power 2003 * 3.05 167 (2) Alabama Power 2003 * 3.96 250 (6) Georgia Power 2003 * 4.76 250 (7) Southern Power 2013 * 6.23 350 (50) Southern Power 2008 * 5.48 150 (13) - -------------------------------------------------------------- *Rate has not been set.
For the year 2002, approximately $1 million was reclassified from other comprehensive income to interest expense. For the year 2003, approximately $2 million is expected to be reclassified.
9. COMMITMENTS
Construction Program
Southern Company is engaged in continuous construction programs, currently estimated to total $2.1 billion in 2003, $2.3 billion in 2004, and $2.4 billion in 2005. 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; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2002, significant purchase commitments were outstanding in connection with the construction program. Southern Company has approximately 4,100 megawatts of additional generating capacity scheduled to be placed in service by 2005.
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Long-Term Service Agreements
The 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 respective units. Total payments to GE under these agreements for facilities owned are currently estimated at $1.2 billion over the 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 purchases are based on various indices at the time of delivery; therefore, only the volume commitments are firm and disclosed in the following chart. Also, Southern Company has entered into various long-term commitments for the purchase of electricity. Total estimated minimum long-term obligations at December 31, 2002 were as follows:
Natural Gas Purchased Year MMBtu Fuel Power - ---- ----------- --------------------- (in millions) (in millions) 2003 199,635 $2,211 $ 116 2004 121,020 1,735 136 2005 58,465 1,296 171 2006 38,960 1,130 178 2007 13,590 1,038 180 2008 and thereafter - 2,347 1,090 - -------------------------------------------------------------- Total commitments 431,670 $9,757 $1,871 ==============================================================
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. The lease provides for a residual value guarantee -- approximately 71 percent of the completion cost -- by Mississippi Power that is due upon termination of the lease in certain circumstances. The lease also includes purchase and renewal options. Upon termination of the lease, Mississippi Power may either exercise its purchase option of the facility or allow it to be sold to a third party. Mississippi Power expects the fair market value of the leased facility to substantially reduce or eliminate its payment under the residual value guarantee. The amount of future minimum operating lease payments exclusive of any payment related to this guarantee will be approximately $25 million annually during the initial term.
Southern Company has other operating lease agreements with various terms and expiration dates. Total operating lease expenses were $171 million, $64 million, and $42 million for 2002, 2001, and 2000, respectively. At December 31, 2002,
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NOTES (continued) Southern Company and Subsidiary Companies 2002 Annual Report
estimated minimum rental commitments for noncancelable operating leases were as follows:
Rail Year Cars Other Total - ---- ----------------------------- (in millions) 2003 $ 37 $ 88 $125 2004 36 78 114 2005 33 66 99 2006 28 56 84 2007 20 43 63 2008 and thereafter 125 152 277 - --------------------------------------------------------------- Total minimum payments $279 $483 $762 ===============================================================
For the 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, 2002, the total notional amount of guarantees was $42 million, all of which will expire by 2007. The estimated fair value of these net contractual commitments outstanding was approximately $19 million at December 31, 2002. Under the terms of the separation agreement, Mirant may not enter into any new commitments under these guarantees after the spin off date. Southern Company's potential exposure under these contractual commitments is not expected to materially differ from the estimated fair value. 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. Mirant must use reasonable efforts to release Southern Company from all such support arrangements and will indemnify Southern Company for any obligations incurred.
Prior to 1999, a subsidiary of Southern Company originated loans to residential customers of the operating companies for heat pump purchases. These loans were sold to Fannie Mae with recourse for any loan with payments outstanding over 120 days. The individual operating companies are responsible for the repurchase of their respective customers' delinquent loans. As of December 31, 2002, the outstanding loans guaranteed by the operating companies were $18 million, and loan loss reserves of $4 million have been recorded.
Southern Company has executed a keep-well agreement with a subsidiary of Southern Holdings -- a direct subsidiary -- 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, Mississippi Power, Georgia Power, and Alabama Power have entered into certain residual value guarantees. Southern Company has also guaranteed certain contingent liabilities of MESH discussed in Note 3.
10. 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 $9.5 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 $88 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 $176 million and $178 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.
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NOTES (continued) Southern Company and Subsidiary Companies 2002 Annual Report
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 between 8 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. However, both companies revised their policy terms on a prospective basis to include an industry aggregate for all terrorist acts. The NEIL aggregate, which applies to all claims stemming from terrorism within a 12-month duration, is $3.24 billion plus any amounts that would be available through reinsurance or indemnity from an outside source. The ANI cap is a $300 million shared industry aggregate.
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.
11. DISCONTINUED OPERATIONS
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 within 12 months of the initial stock offering. On October 2, 2000, Mirant completed its initial public offering of 66.7 million shares of common stock priced at $22 per share. This represented 19.7 percent of the 338.7 million shares outstanding. As a result of the stock offering, Southern Company recorded a $560 million increase in paid-in capital with no gain or loss being recognized.
On February 19, 2001, the Southern Company Board of Directors approved the spin off of its remaining ownership of 272 million Mirant 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.
The distribution resulted in charges of approximately $3.2 billion and $0.4 billion to Southern Company's paid-in capital and retained earnings, respectively. The distribution was treated as a non-cash transaction for purposes of the statement of cash flows.
As a result of the spin off, Southern Company's financial statements reflect Mirant's results of operations, balance sheets, and cash flows as discontinued operations.
Potential Mirant Restatement
In November 2002, Mirant announced that it had identified accounting errors in previously issued financial statements, primarily related to its risk management and marketing operations. As a result of these accounting errors, Mirant reported that its net income for January 1999 through December 2001 was overstated by $51 million. Mirant has stated that the specific periods to which
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NOTES (continued) Southern Company and Subsidiary Companies 2002 Annual Report
these overstatements apply have not been determined. Mirant further announced that it had requested its independent auditors to reaudit Mirant's 2001 and 2000 financial statements and stated that it did not expect that its reaudit could be completed until it files its Form 10-K for the year ended December 31, 2002. If the reaudit of Mirant's 2001 and 2000 financial statements results in adjustments that relate to periods prior to Southern Company's spin off of Mirant, Southern Company's earnings from discontinued operations for such periods could be affected. The impact of any such adjustments would not affect Southern Company's 2002 or any future financial statements.
12. SEGMENT AND RELATED INFORMATION
Southern Company's reportable business segment is the sale of electricity in the Southeast by the five 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 alternative fuel investments, energy-related products and services, and leasing and financing services. Intersegment revenues are not material. Financial data for business segments and products and services are as follows:
Business Segments
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NOTES (continued) Southern Company and Subsidiary Companies 2002 Annual Report
II-52
II-53
II-54
ALABAMA POWER COMPANY
FINANCIAL SECTION
II-55
MANAGEMENT'S REPORT Alabama Power Company 2002 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 system of internal accounting controls is 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 Southern Company audit committee of its board of directors, composed of five independent directors, provides a broad overview of management's financial reporting and control functions. Additionally, a 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
February 17, 2003
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INDEPENDENT AUDITORS' REPORT
Alabama Power Company:
We have audited the accompanying balance sheet and statement of capitalization of Alabama Power Company (a wholly owned subsidiary of Southern Company) as of December 31, 2002, and the related statements of income, comprehensive income, common stockholder's equity, and cash flows for the year 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 audit. The financial statements of Alabama Power Company as of December 31, 2001, and for each of the two years then ended 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 audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the 2002 financial statements (pages II-71 to II-92) present fairly, in all material respects, the financial position of Alabama Power Company at December 31, 2002, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
/s/Deloitte & Touche LLP Birmingham, Alabama February 17, 2003
THE FOLLOWING REPORT OF INDEPENDENT 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(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 2002 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 2002 net income after dividends on preferred stock was $461 million, representing a $74 million (19.3 percent) increase from the prior year. This improvement is 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.
In 2001 earnings 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. Earnings in the year 2000 were $420 million, representing a 5 percent increase from the prior year. This improvement was primarily attributable to an increase in territorial sales partially offset by increased non-fuel operating expenses.
The return on average common equity for 2002 was 13.80 percent compared to 11.89 percent in 2001 and 13.58 percent in 2000. A condensed income statement is as follows: Increase (Decrease) Amount From Prior Year - -------------------------------------------------------------- 2002 2002 2001 2000 - -------------------------------------------------------------- (in millions) Operating revenues $3,710 $124 $(81) $282 - -------------------------------------------------------------- Fuel 970 (31) 38 108 Purchased power 249 (44) (56) 75 Other operation and maintenance 854 71 (56) 30 Depreciation and amortization 398 15 19 17 Taxes other than income taxes 217 2 5 5 - -------------------------------------------------------------- Total operating expenses 2,688 13 (50) 235 ------------------------------------------------------------- Operating income 1,022 111 (31) 47 Other income (expense), net (269) 7 (15) (8) Less -- Income taxes 292 44 (13) 19 - -------------------------------------------------------------- Net Income $ 461 $ 74 $(33) $ 20 ==============================================================
Revenues
Operating revenues for 2002 were $3.7 billion, reflecting a $124 million increase from 2001. The following table summarizes the principal factors that have affected operating revenues for the past three years:
Amount ---------------------------------------- 2002 2001 2000 - ----------------------------------------------------------------- (in thousands) Retail - prior year $2,747,673 $2,952,707 $2,811,117 Change in - Base rates 76,326 22,918 - Sales growth 70,050 (36,197) 58,347 Weather 60,089 (61,846) 21,917 Fuel cost recovery and other (2,921) (129,909) 61,326 - ----------------------------------------------------------------- Total retail 2,951,217 2,747,673 2,952,707 - ----------------------------------------------------------------- Sales for resale -- Non-affiliates 474,291 485,974 461,730 Affiliates 188,163 245,189 166,219 - ----------------------------------------------------------------- Total sales for resale 662,453 731,163 627,949 - ----------------------------------------------------------------- Other operating revenues 96,862 107,554 86,805 - ----------------------------------------------------------------- Total operating revenues $3,710,533 $3,586,390 $3,667,461 ================================================================= Percent change 3.5% (2.2)% 8.3% - ------------------------------------------------------------------
Retail revenues of $3.0 billion in 2002 increased $204 million (7.4 percent) from the prior year, decreased $205 million (6.9 percent) in 2001, and increased $142 million (5 percent) in 2000. 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 October 2001 and April 2002). The Company mitigated these increases to the customer with a decrease to the energy cost recovery factor in April 2002.
Fuel rates billed to customers are designed to fully recover fluctuating fuel costs over a period of time. Lower natural gas prices and increased hydro production combined with decreased costs of purchased power have resulted in an $83 million reduction in under-recovered fuel costs. At December 31, 2002, the Company had completely recovered its previously under-recovered fuel cost. Fuel revenues have no effect on net income because they represent the recording of revenues to offset fuel expenses.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2002 Annual Report
Energy sales for resale outside the service area are predominantly unit power sales under long-term contracts to Florida utilities. Economy energy and energy sold under short-term contracts are also sold for resale outside the service area. Revenues from power sales contracts have both a capacity and energy component. 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 and other outside the service area contracts with non-affiliates, were as follows:
2002 2001 2000 ------------------------------------ (in thousands) Unit power - Capacity $119,193 $124,720 $127,445 Energy 134,051 134,006 127,911 Other power contracts - Capacity 14,613 13,324 11,546 Energy 61,925 91,608 43,964 --------------------------------------------------------------- Total $329,782 $363,658 $310,866 ===============================================================
Capacity revenues from non-affiliates were relatively unchanged over the past three years. There are no significant scheduled declines in capacity until the termination of the unit power sales contracts in 2010.
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. These transactions did not have a significant impact on earnings.
Other operating revenues in 2002 decreased $11 million (9.9 percent) from 2001 due to a decrease in revenues from gas-fueled co-generation steam facilities primarily from lower gas prices and lower demand. Since co-generation steam revenues are generally offset by fuel expenses, these revenues did not have a significant impact on earnings.
The $21 million (23.9 percent) increase in other operating revenues in 2001 and $20 million (30.5 percent) increase in 2000 were primarily attributed to increased steam sales in conjunction with the operation of the Company's co-generation facilities, fuel sales, and rent from electric property.
Kilowatt-hour (KWH) sales for 2002 and the percent change by year were as follows:
KWH Percent Change ----------------------------------- 2002 2002 2001 2000 ----------------------------------- (millions)
Residential 17,403 9.6% (5.3)% 6.8% Commercial 13,363 4.4 (1.5) 5.5 Industrial 21,103 3.1 (7.4) 0.7 Other 204 3.7 (3.9) 2.3 -------- Total retail 52,073 5.5 (5.2) 3.8 Sales for resale - Non-affiliates 15,554 1.8 2.9 19.4 Affiliates 8,844 - 64.7 6.7 -------- Total 76,471 4.1 1.6 6.9 - ------------------------------------------------------------
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.
Although retail sales to industrial customers increased 3.1 percent in 2002, overall sales to industrial customers remain depressed due to the continuing effect of sluggish economic conditions.
Retail energy sales in 2001 decreased by 5.2 percent 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.
The increase in 2000 retail energy sales was primarily due to the strength of business and economic conditions in the Company's service area. Residential energy sales experienced a 6.8 percent increase over the prior year primarily as a result of warmer summer temperatures and colder winter weather conditions compared to 1999.
Expenses
Total 2002 operating expenses of $2.7 billion increased by $13 million or 0.5 percent over the previous year. This slight increase is mainly due to a $35 million increase in administrative and general expenses primarily related to employee salaries, insurance expense and injuries and damages expense, a $19 million increase in production expenses related to boiler plant maintenance, and
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2002 Annual Report
a $15 million increase in depreciation and amortization expenses due to an increase in depreciable property. These increases are offset by a $43 million decrease in purchased power expenses and a $14 million decrease in fuel expenses related to lower coal prices. Fuel expenses, including purchased power, are offset by fuel revenues and have no effect on net income.
In 2001 total operating expenses of $2.7 billion were down $50 million or 1.8 percent compared with 2000. This decline is 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 the system service company and Southern Nuclear, 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.
Total operating expenses of $2.7 billion in 2000 were up $235 million or 9.4 percent compared with the prior year. This increase was mainly due to a $183 million increase in fuel and purchased power costs as a result of warmer summer temperatures and colder winter weather conditions compared to 1999, accompanied by a $23 million increase in maintenance expenses related to overhead line clearing.
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 KWH generated were as follows:
------------------------ 2002 2001 2000 ------------------------ Total generation (billions of KWHs) 71 68 65 Sources of generation (percent) -- Coal 62 64 72 Nuclear 19 18 19 Hydro 6 6 3 Gas 13 12 6 Average cost of fuel per net KWH generated (cents) -- 1.47 1.56 1.54 - ------------------------------------------------------------
In 2002, total fuel and purchased power expenses of $1.2 billion decreased $75 million (5.8 percent) due primarily to lower average fuel cost, while total energy sales increased 3,012 million 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 milder temperatures in 2001. Fuel and purchased power expenses increased $183 million (16 percent) in 2000 compared to 1999 because of hotter-than-normal summer weather in 2000.
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. 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 3.9 percent in 2002, 5.2 percent in 2001, and 4.9 percent in 2000. These increases reflect additions to property, plant, and equipment.
Allowance for Funds Used During Construction (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 completion of construction of Plant Barry Unit 7 and placing it in service in May 2001. In 2000, AFUDC increased $11 million (94.6 percent) as a result of this construction.
Interest expense decreased $26 million (9.9 percent) in 2002. The decrease reflects a decrease in interest on long-term debt due to refinancing activities. Interest expense increased $3 million (1.1 percent) in 2001 compared to 2000. In 2000 interest expense was relatively flat when compared to the previous year.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2002 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 continuing operations for the past three years are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors. The major factor is the ability of the Company to achieve energy sales growth while containing costs and maintaining a stable regulatory environment. Growth in energy sales is subject to a number of factors. These factors include weather, competition, new short- and long-term contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, and the rate of economic growth in the Company's service area.
Assuming normal weather, sales to retail customers are projected to grow approximately 1.8 percent annually on average during 2003 through 2007.
The Company currently operates as a vertically integrated utility providing electricity to customers within its traditional service area located in the state of Alabama. Prices for electricity provided by the Company to retail customers are set by the Alabama Public Service Commission (APSC) 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. Increases in retail rates of 2 percent were effective in April 2002 and October 2001 in accordance with the Rate Stabilization Equalization plan. See Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for additional information.
The rates also provide for adjustments to recognize the placing of new generating facilities into retail service 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.
In April 2000, the APSC approved an amendment to the Company's existing rate structure to provide for the recovery of retail costs associated with certified purchased power agreements. In November 2000, the APSC certified a seven-year purchased power agreement pertaining to a 615 megawatt wholesale generating facility under construction in Autaugaville, Alabama (Plant Harris), which was sold to Southern Power in June 2001. All of the 615 megawatts are scheduled to be available beginning in June 2003. In addition, the APSC certified a seven-year purchase power agreement with a third party for approximately 630 megawatts; one half of the capacity will be available beginning in 2003, while the remaining half is scheduled to be available beginning in 2004. Rate CNP will adjust retail rates one month after the contracted capacity delivery is scheduled to begin.
In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash pre-tax pension income of approximately $56 million in 2002. Future pension income is dependent on several factors including trust earnings and changes to the plan. Current estimates indicate a reversal of recording pension income to recording pension expense by as early as 2007. Postretirement benefit costs for the Company were $23 million in 2002 and are expected to continue to trend upward. A portion of pension income is capitalized based on construction related labor charges. For the Company, pension income and postretirement benefits are a component of the regulated rates and do not have a significant effect on net income. For more information see Note 2 to the financial statements.
Proposed nuclear security legislation is expected to be introduced in the 108th Congress. The Nuclear Regulatory Commission is also considering additional security measures for licensees that could require immediate implementation. Any such requirements could have a significant impact on the Company's nuclear power
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2002 Annual Report
plant and result in increased operation and maintenance expenses as well as additional capital expenditures. The impact of any new requirements would depend upon the development and implementation of the regulations.
The Company is involved in various matters being litigated. See Note 3 to the financial statements for information regarding material issues that could possibly affect future earnings.
Compliance costs related to current and future environmental laws and regulations could affect earnings if such costs are not fully recovered. The Clean Air Act and other important environmental items are discussed later under "Environmental Matters."
Industry Restructuring
The electric utility industry in the United States is continuing to evolve as a result of regulatory and competitive factors. Among the primary agents of change has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows independent power producers (IPPs) to access a utility's transmission network in order to sell electricity to other utilities. This enhances the incentive for IPPs to build power plants for a utility's large industrial and/or commercial customers where retail access is allowed and to sell excess energy to other utilities. Also, electricity sales for resale rates were affected by numerous new energy suppliers, including power marketers and brokers.
This past year, merchant energy companies and traditional electric utilities with significant energy marketing and trading activities came 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 SCS and recent generating capacity additions.
Although the Energy Act does not provide for retail customer access, it was a major catalyst for the recent restructuring and consolidation taking 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 APSC 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 APSC itself would not mandate retail competition or electric industry restructuring without enabling state legislation. Electric utility restructuring would 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.
Continuing to be a low-cost producer could provide opportunities to increase market share and profitability in markets that evolve with changing regulation and competition. Conversely, 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.
FERC Matters
In December 1999, the Federal Energy Regulatory Commission (FERC) issued its final ruling on Regional Transmission Organizations (RTOs). The order encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Southern Company and its operating companies, including the Company, have submitted a series of status reports informing the FERC of progress toward the development of a Southeastern RTO. In these status reports, Southern Company explained that it is developing a for-profit RTO known as SeTrans with a number of non-jurisdictional cooperative and public power entities. In 2001, Entergy Corporation and Cleco Power joined the SeTrans development process. In 2002, the sponsors of SeTrans established a Stakeholder Advisory Committee, which will participate in the development of the RTO, and held public meetings to discuss the SeTrans proposal. On October 10, 2002, the FERC granted Southern Company's and other SeTrans' sponsors petition for a declaratory order regarding the governance structure and the selection process for the Independent System Administrator (ISA) of the SeTrans RTO. The FERC also provided guidance on other
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2002 Annual Report
issues identified in the petition. The SeTrans sponsors announced the selection of ESB International, Ltd. (ESBI) to be the preferred ISA candidate. Should negotiations with this candidate successfully conclude with final agreement among the parties, the SeTrans sponsors intend to seek any state and federal regulatory or other approvals necessary for formation of the SeTrans RTO and the approval of ESBI to serve in the capacity of the SeTrans ISA. The creation of SeTrans is not expected to have a material impact on the Company's financial statements; however, the outcome of this matter 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 a day ahead and spot energy markets; and (7) revise the FERC policy on the pricing of transmission expansions. Comments on certain aspects of the proposal have been submitted by Southern Company and the Company. Any impact of this proposal on the Company will depend on the form in which final rules may be ultimately adopted; however, the Company's revenues, expenses, assets, and liabilities could be adversely affected by changes in the transmission regulatory structure in its regional power market.
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.
Accounting Policies
Critical Policy
The Company's significant accounting policies are described in Note 1 to the financial statements. The Company's only critical accounting policy involves rate regulation. The Company is subject to the provisions of FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of the Company's operation is no longer subject to these provisions, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
New Accounting Standards
Derivatives - -----------
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. In October 2002, the Emerging Issues Task Force (EITF) of the FASB announced accounting changes related to energy trading contracts in Issue No. 02-03. In October 2002, the Company prospectively adopted the EITF's requirements to reflect the impact of certain energy trading contracts on a net basis. This change had no material impact on the Company's income statement. Another change also required certain energy trading contracts to be accounted for on an accrual basis effective January 2003. This change had no impact on the Company's current accounting treatment.
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, establishes 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 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 non-regulated companies to
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2002 Annual Report
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 "Regulatory Assets and Liabilities" and "Depreciation and Nuclear Decommissioning."
Guarantees - ----------
In 2002, the FASB issued Interpretation No. 45, Accounting and Disclosure Requirements for Guarantees. This interpretation requires disclosure of certain direct and indirect guarantees as reflected in Note 8 to the financial statements under "Guarantees." Also, the interpretation requires recognition of a liability at inception for certain new or modified guarantees issued after December 31, 2002. The adoption of Interpretation No. 45 in January 2003 did not have a material impact on the Company's financial statements.
FINANCIAL CONDITION
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 had gross property additions of $635 million in 2002. The majority of funds needed for gross property additions for the last several years have been provided from operating activities, principally from earnings and non-cash charges to income such as depreciation and deferred income taxes. The Statements of Cash Flows provide additional details.
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.
Exposure to Market Risk
The Company is exposed to market risks, including changes in interest rates and certain 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.
The weighted average interest rate on variable long-term debt outstanding at December 31, 2002 was 1.64%. If the Company sustained a 100 basis point change in interest rates for all variable long-term debt, the change would affect annualized interest expense by $10.5 million. To further mitigate the Company's exposure to interest rates, it has entered into interest rate swaps that were designed as cash flow hedges of variable rate debt or anticipated debt issuances. See Note 1 and Note 7 to the financial statements under "Financial Instruments" for additional information. The Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term.
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 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, in October 2001, the APSC 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 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, 2002, 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:
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2002 Annual Report
Changes in Fair Value - --------------------------------------------------------------- 2002 2001 - --------------------------------------------------------------- (in thousands) Contracts beginning of year $ 214 $ 567 Contracts realized or settled (21,088) (509) New contracts at inception - - Changes in valuation techniques - - Current period changes 42,276 156 - -------------------------------------------------------------- Contracts end of year $ 21,402 $ 214 ==============================================================
Source of Year-End Valuation Prices ---------------------------------- Maturity Total ------------------- Fair Value Year 1 1-3 Years - ----------------------------------------------------------------- (in thousands) - ----------------------------------------------------------------- Actively quoted $21,402 $26,462 $(5,060) External sources - - - Models and other methods - - - - ----------------------------------------------------------------- Contracts end of Year $21,402 $26,462 $(5,060) =================================================================
Unrealized gains and losses from mark to market adjustments on contracts related to the retail 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 contracts that do not represent hedges are recognized in the Statements of Income as incurred. At December 31, 2002, the fair value of derivative energy contracts reflected in the financial statements was as follows:
Amounts - ---------------------------------------------------------- (in millions) Regulatory liabilities, net $21.3 Other comprehensive income - Net income 0.1 - ------------------------------------------------------- Total fair value $21.4 =======================================================
For the years ended December 31, 2002 and 2001, approximately $(2.0) million and $2.0 million, respectively, of gains (losses) were recognized in income.
Financing Activities
In 2002, the Company's financing costs decreased due to lower interest rates despite the issuance of new debt during the year. New issues during 2000 through 2002 totaled $2.0 billion and retirement or repayment of higher-cost securities totaled $1.5 billion.
Composite financing rates for long-term debt, preferred stock, and preferred securities for the years 2000 through 2002, as of year-end, were as follows:
2002 2001 2000 - --------------------------------------------------------------- Long-term debt interest rate 5.05% 5.72% 6.60% Preferred stock dividend rate 5.17 4.79 5.18 Preferred securities dividend rate 5.25 6.96 7.38 - ---------------------------------------------------------------
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 2003. Subsequent to December 31, 2002, the Company has refinanced $167 million of securities classified as current on the Balance Sheet with long-term securities. An additional $250 million of securities has been issued to retire long-term debt and for other corporate purposes.
Capital Structure
The Company's ratio of common equity to total capitalization -- including short-term debt -- was 42.6 percent in 2002, 42.8 percent in 2001, and 42.2 percent in 2000. See Note 7 to the financial statements under "Capitalization" for additional information.
Capital Requirements for Construction
Capital expenditures are estimated to be $643 million for 2003, $787 million for 2004, and $948 million for 2005. Over the next three years the Company estimates spending $485 million on environmental related additions including $355 million on Selective Catalytic Reduction facilities, $164 million on Plant Farley including $43 million on replacing reactor vessel heads, $620 million on distribution facilities, and $569 million on transmission additions. See Note 8 to the financial statements for additional details.
Actual construction costs may vary from estimates 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2002 Annual Report
Other Capital Requirements
In addition to the funds required for the Company's construction program, approximately $1.9 billion will be required by the end of 2005 for maturities of long-term debt. The Company plans to continue, when economically feasible, to retire higher cost debt and preferred stock and replace these obligations with lower-cost capital if market conditions permit.
As a result of requirements by the Nuclear Regulatory Commission, 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 approved by the APSC. The amount expensed in 2002 was $18 million. For additional information concerning nuclear decommissioning costs, see Note 1 to the financial statements under "Depreciation and Nuclear Decommissioning."
In 1994 the Company also established an external trust fund for postretirement benefits as ordered by the APSC. 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."
These capital requirements, lease obligations, purchase commitments, and trust requirements - discussed above and in the financial statements - are summarized as follows:
2003 2004 2005 --------------------------------------------------------------- (in millions) Construction expenditures $ 643.0 $787.0 $948.0 Senior Notes 1,117.0 525.0 225.0 Leases - Capital 0.9 1.0 0.5 Operating 28.2 27.2 23.4 Purchase commitments - Fuel 757.7 768.1 522.6 Purchased Power 53.0 83.0 86.0 Long-term service agreements 25.7 15.2 14.3 Trusts - Nuclear decommissioning 20.3 20.3 20.3 Postretirement benefits 5.1 4.9 24.2 - ----------------------------------------------------------------
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 internal sources. 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 trust preferred securities.
To meet short-term cash needs and contingencies, the Company has various internal and external sources of liquidity. At the beginning of 2003, the Company had approximately $23 million of cash and cash equivalents and $923 million of unused credit arrangements with banks. In addition, the Company has substantial cash flow from operating activities and access to the capital markets to meet liquidity needs. Cash flows from operating activities were $951 million in 2002, $838 million in 2001, and $827 million in 2000. Credit arrangements are as follows:
Expires ---------------------------- Total Unused 2003 2004 - ----------------------------------------------------------- (in millions) $923 $923 $533 $390 - -----------------------------------------------------------
Approximately $361 million of the credit facilities expiring in 2003 allow for the execution of term loans for an additional two-year period. See Note 7 to the financial statements under "Bank Credit Arrangements" for additional information.
The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other Southern Company operating companies. At December 31, 2002, the Company had outstanding $37 million of commercial paper.
Environmental Matters
New Source Review Enforcement Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action against the Company in the U.S. District Court in Atlanta, Georgia. The complaint alleges violations of the New Source Review 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2002 Annual Report
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. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal-burning plants constructed or under construction prior to 1978.
The U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia. The EPA refiled its claims against Alabama Power in the U.S. District Court in Alabama. The Company's case has been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA appeal involves many of the same legal issues raised by the actions against the Company. Because the outcome of the TVA appeal could have a significant adverse impact on the Company, it is a party to that case as well. In February 2003, the U.S. District Court in Alabama extended the stay of the EPA litigation proceeding in Alabama until the earlier of May 6, 2003 or a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the related litigation involving TVA.
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 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.
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, a major portion of which is expected to be recovered through existing ratemaking provisions. 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. Compliance was required in two phases -- Phase I, effective in 1995 and Phase II, effective in 2000. Construction expenditures associated with Phase I and Phase II compliance totaled approximately $88 million.
Some of the expenditures required to comply with the Phase II acid rain requirements 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 for meeting the one-hour ozone standard. New emission limits to comply with these requirements must be implemented in May 2003. Two plants in the Birmingham area will be affected. Construction expenditures for compliance with these new rules are currently estimated at approximately $270 million, of which $70 million remains to be spent.
To help bring the remaining nonattainment areas into compliance with the one-hour ozone standard, in 1998 the EPA issued regional nitrogen oxide reduction rules. 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 in Alabama, must comply with the reduction requirements by May 31, 2004. Additional construction expenditures for compliance with these new rules are currently estimated at approximately $292 million, of which $287 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 ozone standards
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2002 Annual Report
unlawful and remanded it to the EPA for further rulemaking. The EPA is expected to propose implementation rules designed to address the court's concerns in 2003 and issue final implementation rules in 2004. The remaining legal challenges to the new standards, which were pending before the U.S. Court of Appeals, District of Columbia Circuit, have been resolved.
The EPA plans to designate areas as attainment or nonattainment with the new eight-hour ozone standard by April 2004, based on air quality data for 2001 through 2003. Several areas within the Company's service area are likely to be designated nonattainment under the new ozone standard. State implementation plans, including new emission control regulations necessary to bring those areas into attainment, could be required as early as 2007. Those state plans 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.
The EPA currently plans to designate areas as attainment or nonattainment with the new fine particulate matter standard by the end of 2004. Those area designations will be based on air quality data collected during 2001 through 2003. Several areas within the Company's service area will likely be designated nonattainment under the new particulate matter standard. State implementation plans, including new regulations necessary to bring those areas into attainment could be required as early as the end of 2007. Those state plans will likely require reductions in sulfur dioxide emissions from power plants. If so, the reductions could be required sometime after 2007. Any additional emission reductions and costs associated with the new fine particulate matter standard cannot be determined at this time.
The EPA has also announced plans to issue a proposed Regional Transport Rule for the fine particulate matter standard by the end of 2003 and to finalize the rule in 2005. This rule would likely require year-round sulfur dioxide and nitrogen oxide emission reductions from power plants as early as 2010. If issued, this rule would likely modify other state implementation plan requirements for attainment of the fine particulate matter standard and the eight-hour ozone standard. It is not possible at this time to determine the effect such a rule would have on the Company.
Further reductions in sulfur dioxide 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 regional haze program calls for States to submit State Implementation Plans in 2007 and 2008 that contain emission reduction strategies for achieving progress toward the visibility improvement goal. In 2002, however, the U.S. Court of Appeals, District of Columbia Circuit, vacated and remanded the BART provisions of the federal Regional Haze rules to the EPA for further rulemaking. Because new BART rules have not been developed and state visibility assessments 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 is in the process of developing CAM plans, which could indicate a need for improved particulate matter controls at affected facilities. Because the plans are still in the early stages of development, the Company cannot determine the extent to which improved controls could be required or the costs associated with any necessary improvements. Actual ongoing monitoring costs are expensed as incurred and are not material for any period presented.
In December 2000, having completed its utility studies for mercury and other hazardous air pollutants (HAPS), the EPA issued a determination that an emission control program for mercury and, perhaps, other HAPS is warranted. The program is being developed under the Maximum Achievable Control Technology provisions of the Clean Air Act. The EPA currently plans to issue proposed rules regulating mercury emissions from electric utility boilers by the end of 2003, and those regulations are scheduled to be finalized by the end of 2004. Compliance could be required as early as 2007. Because the rules have not yet been proposed, the costs associated with compliance cannot be determined at this time.
In December 2002, the EPA issued final and proposed revisions to the New Source Review program under the Clean Air Act. In February 2003, several
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2002 Annual Report
northeastern states petitioned the D.C. Circuit Court for a stay of the final rules. The proposed rules are open to public comment and may be revised before being finalized by the EPA. If fully implemented, these proposed and final regulations could affect the applicability of the New Source Review provisions to activities at the Company's facilities. In any event, any final regulations must be adopted by the states in the Company's service area in order to apply to the Company's facilities. The effect of these proposed and final rules cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent emissions limitations have been proposed. Three of these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2002, and the Clean Air Planning Act of 2002, proposed to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills also proposed to limit emissions of carbon dioxide. None of these bills were enacted into law in the last Congress. Similar bills have been, and are anticipated to be, introduced this year. The Bush Administration's Clear Skies Act was recently reintroduced, and President Bush has stated that it will be a high priority for the Administration. Other bills already introduced include the Climate Stewardship Act of 2003, which proposes capping greenhouse gas emissions. The cost impacts of such legislation would depend upon the specific requirements enacted.
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 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. Because this initiative is still under development, it is not possible to determine the effect on the company at this time.
The Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous 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. The Company may be liable for a portion 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 is developing new rules aimed at reducing impingement and entrainment of fish and fish larvae at cooling water intake structures that will require numerous biological studies, and perhaps, retrofits to some intake structures at existing power plants. The new rule was proposed in February 2002 and will be finalized by August 2004. The impact of any new standards will depend on the development and implementation of applicable regulations.
Also, under the Clean Water Act, the EPA and ADEM are developing total maximum daily loads (TMDLs) for certain impaired waters. Establishment of maximum loads by the EPA or 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 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.
The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including limits on pollutant discharges to impaired waters, hazardous waste disposal requirements, and other regulatory matters. The impact of any new standards 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2002 Annual Report
Compliance with possible additional federal or state legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could also significantly affect the Company. The impact of any new legislation, or changes to existing legislation, could affect many areas of the Company's operations. The full impact of any such changes cannot, however, be determined at this time.
Cautionary Statement Regarding Forward-Looking Information
The Company's 2002 Annual Report includes forward-looking statements in addition to historical information. Forward-looking information includes, among other things, statements concerning projected retail sales growth and scheduled completion of new generation. 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 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 and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations; current and future litigation, including the pending EPA civil action against the Company; the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates; the impact of fluctuations in commodity prices, interest rates, and customer demand; state and federal rate regulations; political, legal, and economic conditions and developments in the United States; internal restructuring or other restructuring options that may be pursued; the ability of counterparties of the Company to make payments as and when due; the effects of, and changes in, economic conditions in the areas in which the Company operates, including the current soft economy; the direct or indirect effects on the Company's business resulting from the terrorist incidents on September 11, 2001, or any similar such incidents or responses to such incidents; financial market conditions and the results of financing efforts; the timing and acceptance of the Company's new product and service offerings; the ability of the Company to obtain additional generating capacity at competitive prices; weather and other natural phenomena; and other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed from time to time by the Company with the Securities and Exchange Commission.
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NOTES TO FINANCIAL STATEMENTS Alabama Power Company 2002 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 operating companies, Southern Power Company (Southern Power), a system service company, Southern Communications Services (Southern LINC), Southern Company Gas (Southern GAS), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The 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. 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 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. 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 operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern GAS, which began operation in August 2002, is a competitive retail natural gas business serving communities in Georgia. Southern Holdings is an intermediate holding subsidiary for Southern Company's investments in leveraged leases, alternative fuel products, and an energy service business. Southern Nuclear provides services to the operating companys' 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 Alabama Public Service Commission (APSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by its respective 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 the system service company 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, $183 million, and $187 million during 2002, 2001, and 2000, respectively. Cost allocation methodologies used by the system service company 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, and employee relations; and other services with respect to business and operations. Costs for these services amounted to $154 million, $160 million, and $148 million during 2002, 2001, and 2000, 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 $6.4 million in 2002. See Note 4 for additional information.
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. The Company has entered into an agreement with Southern Power to operate and maintain Plant Harris and provide fuel at cost beginning in June 2003.
The operating companies, including the Company, Southern Power, and Southern GAS may jointly enter into various types of wholesale energy, natural gas and
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certain other contracts, either directly or through the system service company as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements.
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 the following:
2002 2001 -------------------- (in millions) Deferred income tax charges $ 327 $ 335 Premium on reacquired debt 104 77 Department of Energy assessments 17 21 Vacation pay 34 32 Deferred income tax credits (177) (203) Natural disaster reserve (12) (12) Fuel-hedging assets - 4 Fuel-hedging liabilities (21) (2) Other regulatory assets 56 55 Other regulatory liabilities (12) (4) - -------------------------------------------------------------- Total $ 316 $ 303 ==============================================================
See "Depreciation and Nuclear Decommissioning" in this note for information regarding significant regulatory assets and liabilities created as a result of the January 1, 2003, adoption of FASB Statement No. 143, Accounting for Asset Retirement Obligations.
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.
Revenues and Fuel Costs
The Company currently 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. 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 periods.
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 continue 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 $63 million in 2002, $58 million in 2001, and $61 million in 2000. 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 fuel storage capacity is available at Plant Farley to maintain full-core discharge capability until the refueling outage scheduled in 2006 for Farley Unit 1 and the refueling outage scheduled in 2008 for Farley Unit 2. Procurement of on-site dry spent fuel storage capacity at Plant Farley is in progress, with the intent to place the capacity in operation in 2005.
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 $17 million at December 31, 2002. This obligation is recorded in other deferred credits in the accompanying Balance Sheets.
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NOTES (continued) Alabama Power Company 2002 Annual Report
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.2 percent in 2002, 2001, and 2000. 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 decommissioning nuclear facilities and removal of other facilities. Prior to January 2003, in accordance with regulatory requirements, 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 January 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 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 cost must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life.
There was no cumulative effect to net income resulting from the adoption of Statement No. 143. The Company received an accounting order from the APSC to defer the transition adjustment; therefore, the Company recorded a related regulatory liability of $71 million to reflect the Company's regulatory treatment of these costs under Statement No. 71. The initial Statement No. 143 liability the Company recognized was $301 million, of which $310 million was removed from the accumulated depreciation reserve. The amount capitalized to property, plant, and equipment was $63 million.
The liability recognized to retire long-lived assets primarily relates to the Company's nuclear facility, Plant Farley. In addition, the Company has retirement 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 its 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 as ordered by the APSC. It is estimated that this annual difference will be approximately $4 million. The APSC regulatory order states that actual asset removal costs will be recoverable in rates.
Statement No. 143 does not permit non-regulated companies to continue accruing future retirement costs for long-lived assets they do not have a legal obligation to retire. However, in accordance with the regulatory treatment of these costs, the Company will continue to recognize the removal costs for these other obligations in their depreciation rates. As of January 1, 2003, the amount included in the accumulated depreciation reserve that represents a regulatory liability for these costs was $550 million.
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. Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the APSC. 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, and ultimate cost is the estimate to decommission the facility as of its retirement date. The estimated costs of decommissioning -- both site study costs and ultimate costs - based on the most current study for Plant Farley were as follows:
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Site study year 1998
Decommissioning periods: Beginning year 2017 Completion year 2031 ----------------------------------------------------------- (in millions) Site study costs: Radiated structures $629 Non-radiated structures 60 ----------------------------------------------------------- Total $689 =========================================================== (in millions) Ultimate costs: Radiated structures $1,868 Non-radiated structures 178 ----------------------------------------------------------- Total $2,046 ===========================================================
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 APSC. The amount expensed in 2002 and fund balances as of December 31, 2002 were as follows:
(in millions) Amount expensed in 2002 $ 18 ------------------------------------------------------------
Accumulated provisions: External trust funds, at fair value $292 Internal reserves 34 ------------------------------------------------------------ Total $326 ============================================================
All of the Company's decommissioning costs are approved for recovery by the APSC through the ratemaking process. Significant assumptions include an estimated inflation rate of 4.5 percent and an estimated trust earnings rate of 7.0 percent. The Company expects the APSC to periodically review and adjust, if necessary, the amounts collected in rates for the anticipated cost of decommissioning.
The Company has informed the NRC that the Company plans to submit an application in September 2003 to extend the operating license for Plant Farley for 20 additional years.
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.
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. The composite rate used to determine the amount of AFUDC was 8.2 percent in 2002, 7.7 percent in 2001, and 9.6 percent in 2000. AFUDC and interest capitalized, net of income tax, as a percent of net income after dividends on preferred stock was 3.3 percent in 2002 and 2001, and 8.4 percent in 2000.
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 estimated 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 APSC 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 2002, the Company accrued $34.4 million to the nuclear refueling outage reserve and at December 31, the reserve balance was $9.7 million.
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NOTES (continued) Alabama Power Company 2002 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 with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a 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 reevaluated 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 APSC 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 2002, the Company accrued $3 million to the reserve and at December 31, the reserve balance was $11.8 million.
Comprehensive Income
Comprehensive income - consisting 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 - is presented in the financial statements. 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. For additional information, see Note 7.
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 are derivatives. However, in many cases, these contracts qualify as normal purchases and sales and are accounted for under the accrual method. Other 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. Contracts that do not qualify for the normal purchase and sale exception and that do not meet the hedge requirements 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.
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NOTES (continued) Alabama Power Company 2002 Annual Report
Other Company 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, 2002 $3,967 $4,065 At December 31, 2001 3,744 3,800 Preferred Securities: At December 31, 2002 300 303 At December 31, 2001 347 346 ------------------------------------------------------------
The fair value for long-term debt and preferred securities was based on either closing market prices or closing prices of comparable instruments.
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 Company provides certain medical care and life insurance benefits for retired employees. Substantially all employees may become eligible for such benefits when they retire. The Company funds trusts to the extent deductible under federal income tax regulations or to the extent required by the APSC and the FERC. In late 2000, as well as 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.
Plan assets consist primarily of domestic and international equities, global fixed income securities, real estate, and private equity investments. The measurement date for plan assets and obligations is September 30 of each year. The weighted average rates assumed in the actuarial calculations for both the pension and postretirement benefit plans were as follows:
2002 2001 2000 - --------------------------------------------------------------- Discount 6.50% 7.50% 7.50% Annual salary increase 4.00 5.00 5.00 Long-term return on plan assets 8.50 8.50 8.50 - --------------------------------------------------------------
Pension Plan
Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows:
Projected Benefit Obligations ------------------------- 2002 2001 - ------------------------------------------------------------- (in millions) Balance at beginning of year $1,011 $ 925 Service cost 26 25 Interest cost 74 70 Benefits paid (61) (56) Actuarial gain and employee transfers 16 (1) Amendments 22 48 - ------------------------------------------------------------- Balance at end of year $1,088 $1,011 =============================================================
Plan Assets ------------------------- 2002 2001 - ------------------------------------------------------------- (in millions) Balance at beginning of year $1,584 $1,921 Actual return on plan assets (106) (277) Benefits paid (61) (56) Employee transfers 2 (4) - ------------------------------------------------------------- Balance at end of year $1,419 $1,584 =============================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
2002 2001 - --------------------------------------------------------------- (in millions) Funded status $331 $ 573 Unrecognized transition obligation (10) (15) Unrecognized prior service cost 93 78 Unrecognized net gain (loss) (40) (322) - --------------------------------------------------------------- Prepaid asset, net 374 314 Portion included in benefit obligations 16 15 - --------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $390 $ 329 ===============================================================
In 2002 and 2001, amounts recognized in the Balance Sheets for accumulated other comprehensive income and intangible assets were $6.7 million and $4.8 million, and $0 and $6.3 million, respectively.
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NOTES (continued) Alabama Power Company 2002 Annual Report
Components of the pension plan's net periodic cost were as follows:
2002 2001 2000 - --------------------------------------------------------------- (in millions) Service cost $ 26 $ 25 $ 23 Interest cost 74 70 65 Expected return on plan assets (138) (131) (119) Recognized net actuarial gain (20) (22) (19) Net amortization 2 1 (1) - --------------------------------------------------------------- Net pension cost (income) $ (56) $ (57) $ (51) ===============================================================
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 ------------------------ 2002 2001 - ------------------------------------------------------------ (in millions) Balance at beginning of year $348 $264 Service cost 5 5 Interest cost 26 24 Benefits paid (20) (18) Actuarial gain and employee transfers 46 (13) Amendments - 86 - ------------------------------------------------------------ Balance at end of year $405 $348 ============================================================
Plan Assets ------------------------ 2002 2001 - ----------------------------------------------------------- (in millions) Balance at beginning of year $169 $192 Actual return on plan assets (12) (24) Employer contributions 21 19 Benefits paid (20) (18) - ------------------------------------------------------------ Balance at end of year $158 $169 ============================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows: 2002 2001 - -------------------------------------------------------------- (in millions) Funded status $(247) $(179) Unrecognized transition obligation 41 45 Prior service cost 77 82 Unrecognized net actuarial gain 66 (9) Fourth quarter contributions 8 8 - -------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ (55) $ (53) ==============================================================
Components of the plan's net periodic cost were as follows:
2002 2001 2000 - -------------------------------------------------------------- (in millions) Service cost $ 5 $ 5 $ 4 Interest cost 25 24 19 Expected return on plan assets (16) (15) (13) Net amortization 9 7 4 - -------------------------------------------------------------- Net postretirement cost $ 23 $ 21 $ 14 ==============================================================
An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 8.75 percent for 2002, 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, 2002 as follows:
1 Percent 1 Percent Increase Decrease - ------------------------------------------------------------- (in millions) Benefit obligation $32 $28 Service and interest costs 3 2 =============================================================
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee's base salary. Total matching contributions made to the plan for the years 2002, 2001, and 2000 were $12 million, $12 million, and $11 million, respectively.
Work Force Reduction Programs
The Company has incurred costs for work force reduction programs totaling $13.6 million, $13.0 million and $2.6 million for the years 2002, 2001 and 2000, respectively. These costs were deferred and are being amortized in accordance with regulatory treatment over 22 month periods. The unamortized balance of these costs was $5.1 million at December 31, 2002.
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NOTES (continued) Alabama Power Company 2002 Annual Report
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are also 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 currently filed against the Company cannot be predicted at this time; however, after consultation with legal counsel, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on the Company's financial statements.
Environmental Protection Agency Litigation
In November 1999, the EPA brought a civil action in U.S. District Court in Georgia against the Company. The complaint alleges violations of the New Source Review 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 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.
The EPA concurrently issued to the Company a notice of violation relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation. The complaint and the notice of violation are similar to those brought against and issued to several other electric utilities. The complaint and the notice of violation allege that the Company failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. The U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia. The EPA refiled its claims against Alabama Power in U.S. District Court in Alabama.
The Company's case has been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA appeal involves many of the same legal issues raised by the actions against the Company. Because the outcome of the TVA appeal could have a significant adverse impact on the Company, it is a party to that case as well. In February 2003, the U.S. District Court in Alabama extended the stay of the EPA litigation proceeding in Alabama until the earlier of May 6, 2003 or a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the related litigation involving TVA.
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. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and 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.
Retail Rate Adjustment Procedures
The APSC 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. In March 2002, the APSC 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 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.
In April 2000, the APSC approved an amendment to the Company's existing rate structure to provide for the recovery of retail costs associated with certified purchased power agreements. In November 2000, the APSC certified a seven-year
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purchased power agreement pertaining to a 615 megawatt wholesale generating facility under construction at Plant Harris, which was sold to Southern Power in June 2001. All of the 615 megawatts are scheduled to be available beginning in June 2003. In addition, the APSC certified a seven-year purchased power agreement with a third party for approximately 630 megawatts; one half of the capacity will be available beginning in 2003 while the remaining half is scheduled to be available beginning in 2004. Rate CNP will adjust retail rates one month after the contracted capacity delivery is scheduled to begin.
In October 2001, the APSC 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 APSC votes to modify or discontinue them.
4. JOINT OWNERSHIP AGREEMENTS
The Company and Georgia 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, 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 expenses totaled $84 million in 2002, $80 million in 2001, and $85 million in 2000 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.
At December 31, 2002, the capitalization of SEGCO consisted of $59 million of equity and $92 million of debt on which the annual interest requirement is $2.2 million. SEGCO paid dividends totaling $5.8 million in 2002, $0.7 million in 2001, and $5.1 million in 2000, of which one-half of each was paid to the Company. In addition, the Company recognizes 50 percent of SEGCO's net income.
The Company's percentage ownership and investment in jointly-owned generating plants at December 31, 2002 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 Company. (2) Jointly owned with Alabama Electric Cooperative, Inc.
Company Accumulated Facility Investment Depreciation --------------------- -------------- --------------- (in millions) Greene County $105 $ 51 Plant Miller Units 1 and 2 760 341 ----------------------------------------------------------
The Company has contracted to operate and maintain the jointly owned facilities as agent for their co-owners. The Company's proportionate share of their plant operating expenses is included in the operating expenses in the Statements of Income.
5. LONG-TERM POWER SALES AGREEMENTS
General
The Company and the other operating companies of Southern Company have entered into long-term contractual agreements for the sale of capacity to certain non-affiliated utilities located outside the system's service area. These
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NOTES (continued) Alabama Power Company 2002 Annual Report
agreements are firm and related to specific generating units. Because the energy is generally provided at cost under these agreements, profitability is primarily affected by capacity revenues.
Unit power from Plant Miller is being sold to Florida Power Corporation (FPC), Florida Power & Light Company (FP&L), and Jacksonville Electric Authority (JEA). Under these agreements approximately 1,239 megawatts of capacity are scheduled to be sold annually through the expiration of the contract in 2010. The Company's capacity revenues from these unit power sales amounted to $119 million in 2002, $125 million in 2001, and $127 million in 2000.
Alabama Municipal Electric Authority (AMEA) Capacity Contracts
In October 1991, the Company entered into a firm power sales contract with 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, 2002, $32.6 million of these bonds was held by the escrow agent under the contract.
6. INCOME TAXES
At December 31, 2002, the Company's tax-related regulatory assets and liabilities were $327 million and $177 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 current enacted tax law and to unamortized investment tax credits.
Details of the income tax provisions are as follows:
2002 2001 2000 ------------------------------- (in millions) Total provision for income taxes: Federal -- Current $209 $234 $168 Deferred 41 (20) 60 - --------------------------------------------------------------- 250 214 228 - --------------------------------------------------------------- State -- Current 35 37 27 Deferred 7 (2) 7 - --------------------------------------------------------------- 42 35 34 - --------------------------------------------------------------- Total $292 $249 $262 ===============================================================
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:
2002 2001 --------------- (in millions) Deferred tax liabilities: Accelerated depreciation $1,081 $1,034 Property basis differences 381 390 Fuel cost adjustment - 28 Premium on reacquired debt 39 29 Pensions 103 89 Other 38 23 --------------------------------------------------------------- Total 1,642 1,593 - ---------------------------------------------------------------- Deferred tax assets: Capacity prepayments 11 13 Other deferred costs 13 14 Postretirement benefits 18 21 Unbilled revenue 20 18 Other 87 93 - ---------------------------------------------------------------- Total 149 159 - ---------------------------------------------------------------- Total deferred tax liabilities, net 1,493 1,434 Portion included in current liabilities, net (56) (47) - ---------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $1,437 $1,387 ================================================================
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 2002, 2001, and 2000. At December 31, 2002, all investment tax credits available to reduce federal income taxes payable had been utilized.
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NOTES (continued) Alabama Power Company 2002 Annual Report
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
2002 2001 2000 ------------------------ Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.5 3.5 3.1 Non-deductible book depreciation 1.3 1.5 1.4 Differences in prior years' deferred and current tax rates (1.2) (1.3) (1.3) Other (0.5) (0.5) (0.7) - ------------------------------------------------------------- Effective income tax rate 38.1% 38.2% 37.5% =============================================================
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 Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability.
7. CAPITALIZATION
Mandatorily Redeemable Preferred Securities
Statutory business trusts formed by the Company, of which the Company owns all the common securities, have issued mandatorily redeemable flexible trust preferred securities as follows:
Date of Maturity Issue Amount Rate* Notes Date --------------------------------------------------- (millions) (millions) Trust IV 10/2002 $ 100 4.75% $103 10/2042 Trust V 10/2002 200 5.50 206 10/2042
* Issued at a five year initial fixed rate and a seven year initial fixed rate for Trust IV and Trust V, respectively, and thereafter, at fixed rates determined through remarketings for specific periods of varying length or at floating rates determined by reference to 3-month LIBOR plus 2.91% and 3.10%, respectively.
Substantially all of the assets of each trust are junior subordinated notes issued by the Company in the respective approximate principal amounts set forth above.
The Company considers that the mechanisms and obligations relating to the preferred securities, taken together, constitute a full and unconditional guarantee by the Company of the Trusts' payment obligations with respect to the preferred securities.
The Trusts are subsidiaries of the Company and accordingly are consolidated in the Company's financial statements.
The securities issued by Trusts I, II, and III were redeemed in 2002.
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. The amount of pollution control revenue bonds outstanding was $560 million at December 31, 2002 and 2001.
Senior Notes
The Company issued a total of $975 million of unsecured senior notes in 2002. The proceeds of these issues were used to redeem higher cost debt and for other general corporate purposes.
At December 31, 2002 and 2001, the Company had $3.4 billion and $2.9 billion, respectively, of senior notes outstanding. These senior notes are subordinate to all secured debt of the Company which amounted to approximately $302 million at December 31, 2002.
Capitalized Leases
The estimated aggregate annual maturities of capitalized lease obligations through 2006 are as follows: $0.9 million in 2003, $1.0 million in 2004, $0.5 million in 2005, and $0.1 million in 2006.
Securities 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:
2002 2001 ------------------------ (in thousands) First mortgage bond maturities and redemptions $ - $4,498 Other long-term debt maturities and redemptions 1,117,945 884 -------------------------------------------------------------- Total long-term debt due within one year $1,117,945 $5,382 ==============================================================
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NOTES (continued) Alabama Power Company 2002 Annual Report
Bank Credit Arrangements
The Company maintains committed lines of credit in the amount of $923 million (including $454 million of such lines which are dedicated to funding purchase obligations relating to variable rate pollution control bonds). Of these lines, $533 million expire at various times during 2003 and $390 million expire in 2004. In certain cases, such lines 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 1/8 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. An annual 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. Exceeding this debt level would result in a default under the credit arrangements. In addition, the credit arrangements typically contain cross default provisions on other indebtedness of the Company that would be triggered if the Company defaulted on other indebtedness above a specified threshold. The Company is currently in compliance with all such covenants. Borrowings under unused credit arrangements totaling $74 million would be prohibited if the Company experiences a material adverse change (as defined in such arrangements).
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 pursuant to arrangements with banks for uncommitted lines of credit and through extendible commercial note programs. At December 31, 2002, there were no extendible commercial notes outstanding. The amount of commercial paper outstanding at December 31, 2002 was $37 million.
At December 31, 2002, the Company had regulatory approval to have outstanding up to $1 billion of short-term borrowings.
Financial Instruments
The Company enters into interest rate swaps to hedge exposure to interest rate changes. Swaps related to fixed rate securities are accounted for as fair value hedges. Swaps related to variable rate securities or forecasted transactions are accounted for as cash flow hedges. The swaps are generally structured to mirror the terms of the hedged debt instruments; therefore, no material ineffectiveness has been recorded in earnings. The gain or loss in fair value for cash flow hedges is recorded in other comprehensive income and will be recognized in earnings over the life of the hedged items.
At December 31, 2002, the Company had $1.25 billion notional amount of interest rate swaps outstanding with net deferred losses of $15 million as follows:
Cash Flow Hedges
Weighted Average ----------------------- Variable Fixed Fair Rate Rate Notional Value Maturity Received Paid Amount (Loss) - ------------------------------------------------------------- (in millions) 2003 1.95 3.02 $350 $(5) 2004 1.43 1.63 486 (2) 2003 * 3.05 167 (2) 2003 * 3.96 250 (6) - ------------------------------------------------------------- *Rate has not been set.
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.
8. COMMITMENTS
Construction Program
The Company's construction program includes significant projects related to transmission, distribution and generating facilities, including the expenditures necessary to comply with environmental regulation. The Company currently estimates property additions to be $643 million in 2003, $787 million in 2004, and $948 million in 2005.
The capital budget is subject to periodic review and revision, and actual capital costs incurred may vary from 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; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2002, significant purchase commitments were outstanding in connection with the construction program. There can be no assurance that costs related to capital expenditures will be fully recovered.
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NOTES (continued) Alabama Power Company 2002 Annual Report
Southern Company has guaranteed Southern Power obligations totaling $6.6 million for the Company's construction of transmission interconnection facilities to Plant Harris.
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 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. 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. Estimated total long-term obligations at December 31, 2002 were as follows:
Commitments ----------------------------------- Non- Year Affiliated Affiliated Total - ---- ----------------------------------- (in millions) 2003 $ 37 $ 16 $ 53 2004 49 34 83 2005 49 37 86 2006 49 38 87 2007 49 39 88 2008 and thereafter 111 103 214 - -------------------------------------------------------------- Total commitments $344 $267 $611 ==============================================================
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. Total estimated long-term obligations at December 31, 2002, were as follows:
Year Commitments - ---- ---------------- (in millions) 2003 $ 772 2004 782 2005 537 2006 448 2007 453 2008 and thereafter 280 - -------------------------------------------------------------- Total commitments $3,272 ==============================================================
In addition, the system service company acts as agent for the five operating companies, Southern Power, and Southern GAS with regard to natural gas purchases. Natural gas purchases (in dollars) are based on various indices at the actual time of delivery; therefore, only the volume commitments are firm. The Company's committed volumes allocated based on usage projections, as of December 31, 2002, are as follows:
Year Natural Gas - ---- ----------- (MMBtu) 2003 91,672,637 2004 53,978,335 2005 20,562,820 2006 12,962,557 2007 4,534,876 - ------------------------------------------------------------ Total commitments 183,711,225 ============================================================
Additional commitments for fuel will be required to supply the Company's future needs.
Acting as an agent for all of Southern Company's operating companies, Southern Power, and Southern GAS, the system service company may enter into various types of wholesale energy and natural gas contracts. Under these agreements, each of the operating companies, Southern Power, and Southern GAS may be jointly and severally liable for the obligations of each of the operating companies. Accordingly, the creditworthiness of Southern Power and Southern GAS is currently inferior to the creditworthiness of the operating companies. Southern Company has entered into keep-well agreements with each of the
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NOTES (continued) Alabama Power Company 2002 Annual Report
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 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 $29.6 million in 2002, $27.9 million in 2001, and $20.9 million in 2000. Of these amounts, $19.1 million, $21.1 million, and $20.9 million for 2002, 2001, and 2000, respectively, relates to the railcar leases and is recoverable through the Company's energy cost recovery clause. At December 31, 2002, estimated minimum rental commitments for noncancellable operating leases were as follows:
Vehicles Year Railcars & Other Total - -------------------------------------------------------------- (in millions) 2003 $18.6 $ 9.6 $28.2 2004 18.2 9.0 27.2 2005 15.5 7.9 23.4 2006 10.6 5.6 16.2 2007 3.3 2.8 6.1 2008 and thereafter 33.4 4.2 37.6 - -------------------------------------------------------------- Total minimum payments $99.6 $39.1 $138.7 ==============================================================
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 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, 2002, 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.
9. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988 (the 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 $9.5 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $300 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums which could be assessed, after a nuclear incident, against all owners of nuclear reactors. The Company could be assessed up to $88 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 the Company is $176 million per incident but not more than an aggregate of $20 million to be paid for each incident in any one year.
The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members' nuclear generating facilities.
Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.
NEIL also covers the additional cost 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 between 8 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 three 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 stations would be covered under their insurance. However, both companies revised their policy terms on a prospective basis to include an industry aggregate for all terrorist
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NOTES (continued) Alabama Power Company 2002 Annual Report
acts. The NEIL aggregate, which applies to all claims stemming from terrorism within a 12 month duration, is $3.24 billion plus any amounts that would be available through reinsurance or indemnity from an outside source. The ANI cap is a $300 million shared industry aggregate.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.
All retrospective assessments, whether generated for liability, property or replacement power may be subject to applicable state premium taxes.
10. QUARTERLY FINANCIAL INFORMATION (Unaudited)
Summarized quarterly financial data for 2002 and 2001 are as follows:
Net Income After Dividends Quarter Operating Operating on Preferred Ended Revenues Income Stock - -------------------- ------------ ----------- ------------- (in millions)
March 2002 $ 802 $191 $ 72 June 2002 924 256 116 September 2002 1,119 393 201 December 2002 865 182 72
March 2001 $ 850 $180 $ 70 June 2001 904 194 75 September 2001 1,061 362 180 December 2001 772 175 62 - ----------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions.
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GEORGIA POWER COMPANY
FINANCIAL SECTION
II-95
MANAGEMENT'S REPORT Georgia Power Company 2002 Annual Report
The management of Georgia Power Company has prepared this annual report and is responsible for the financial statements and related information. 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 based upon the recognition that the cost of the system should not exceed its benefits. The Company believes that its system of internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is 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 five independent directors, provides a broad overview of management's financial reporting and control functions. Additionally, a committee of Georgia Power'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 President and Chief Executive Officer
/s/Allen L. Leverett Allen L. Leverett Executive Vice President, Treasurer and Chief Financial Officer
February 17, 2003
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INDEPENDENT AUDITORS' REPORT
Georgia Power Company:
We have audited the accompanying balance sheet and statement of capitalization of Georgia Power Company (a wholly owned subsidiary of Southern Company) as of December 31, 2002, and the related statements of income, comprehensive income, common stockholder's equity, and cash flows for the year then ended. These financial statements are the responsibility of Georgia Power's management. Our responsibility is to express an opinion on these financial statements based on our audit. The financial statements of Georgia Power as of December 31, 2001, and for each of the two years then ended 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 audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the 2002 financial statements (pages II-111 to II-133) present fairly, in all material respects, the financial position of Georgia Power Company at December 31, 2002, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.
/s/Deloitte & Touche LLP Atlanta, Georgia February 17, 2003
THE FOLLOWING REPORT OF INDEPENDENT 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(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 2002 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power 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 is attributed to 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. The Company's 2000 earnings totaled $559 million, representing an $18 million (3.3 percent) increase over the prior year due to increased sales and continued control of operating expenses.
Increase (Decrease) Amount From Prior Year ----------------------------------- 2002 2002 2001 2000 - ---------------------------------------------------------------- (in millions) Operating revenues $ 4,822 $ (144) $ 95 $ 414 - ---------------------------------------------------------------- Fuel 1,003 64 (79) 98 Purchased power 685 (87) 175 206 Other operation and maintenance 1,325 85 41 4 Depreciation and amortization 403 (197) (19) 66 Taxes other than income taxes 202 (1) (1) 2 - ---------------------------------------------------------------- Total operating expenses 3,618 (136) 117 376 - ---------------------------------------------------------------- Operating income 1,204 (8) (22) 38 Other income and (expense) (229) 9 76 (11) Less - Income taxes 357 (7) 3 9 - ---------------------------------------------------------------- Net income $ 618 $ 8 $ 51 $ 18 ================================================================
Revenues
Operating revenues in 2002, 2001, and 2000 and the percent of change from the prior year are as follows:
Amount ------------------------------------- 2002 2001 2000 ------------------------------------- (in millions)
Retail - prior year $4,349 $4,317 $4,050 Change in - Base rates (118) - (24) Sales growth and other 2 90 53 Weather 82 (107) 55 Fuel cost recovery and other clauses (27) 49 183 - -------------------------------------------------------------------- Total retail 4,288 4,349 4,317 - -------------------------------------------------------------------- Sales for resale - Non-affiliates 271 366 298 Affiliates 98 100 96 - -------------------------------------------------------------------- Total sales for resale 369 466 394 - -------------------------------------------------------------------- Other operating revenues 165 151 160 - -------------------------------------------------------------------- Total operating revenues $4,822 $4,966 $4,871 ==================================================================== Percent change (2.9%) 2.0% 9.3% - --------------------------------------------------------------------
Retail base revenues of $3.068 billion in 2002 decreased by $34 million (1.1 percent) from 2001 primarily due to a base rate reduction effective January 2002 under the retail rate order and generally lower prices to large business customers. This decrease was partially offset by a 10.1 percent increase in residential kilowatt-hour sales due to warmer weather.
Retail base revenues of $3.102 billion in 2001 decreased $17 million (0.5 percent) from 2000, primarily due to a 2.5 percent decrease in retail kilowatt-hour sales from the prior year. Milder-than-normal weather and a slowdown in the economy contributed to the decline in such sales. Retail base revenues of $3.119 billion in 2000 increased $84 million from the prior year primarily due to a 4.9 percent increase in retail kilowatt-hour sales due to warmer summer temperatures and colder winter weather.
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, 2002, the Company had $118 million in underrecovered fuel costs. Under a GPSC rate order, the fuel cost recovery rate was increased effective June 2001 to allow for an estimated 24-month recovery of
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2002 Annual Report
the deferred underrecovered fuel costs. Also, effective January 1, 2002, the Company is allowed to collect a carrying cost on average underrecovered fuel balances.
Wholesale revenues from sales to non-affiliated utilities were:
2002 2001 2000 --------------------------- (in millions) Unit power sales -- Capacity $ 34 $ 26 $ 30 Energy 34 35 25 Other power sales -- Capacity 41 72 67 Energy 162 233 176 - ----------------------------------------------------------- Total $271 $366 $298 ===========================================================
Revenues from unit power contracts increased $7 million in 2002 due to higher capacity charges and $6 million in 2001 due to increased energy sales, while remaining constant in 2000. See Note 7 to the financial statements for further information regarding these sales. Revenues from other non-affiliated sales decreased $102 million (33.4 percent) in 2002 and increased $62 million in 2001 and $88 million in 2000 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 electric system, as well as purchases of energy, will vary from year to year depending on demand and the availability and cost of generating resources at each company. These transactions do not have a significant impact on earnings.
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 and revenues from outdoor lighting and the transmission of electricity. 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. Other operating revenues in 2000 increased $39 million (32.8 percent) due to increased revenues from the transmission of electricity and gains on the sale of generating plant emission allowances.
Kilowatt-hour (KWH) sales for 2002 and the percent change by year were as follows: Percent Change ---------------------------- KWH 2002 2002 2001 2000 --------------------------------------- (in billions)
Residential 22.1 10.1% (2.8)% 6.6% Commercial 27.0 1.7 3.4 8.1 Industrial 25.7 1.5 (8.0) 0.9 Other 0.6 1.7 2.5 3.2 ------ Total retail 75.4 4.0 (2.5) 4.9 ------ Sales for resale - Non-affiliates 8.1 (0.5) 25.5 27.7 Affiliates 4.0 26.5 28.7 35.6 ------ Total sales for resale 12.1 7.0 26.3 29.8 ------ Total sales 87.5 4.4 0.5 7.1 ====== - ------------------------------------------------------------
Residential sales increased 10.1 percent in 2002 due to the effect of the warmer weather. Commercial and industrial 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 sales decreased 2.8 percent in 2001 due to milder-than-normal weather. Commercial sales increased 3.4 percent due to an increase in customers, while industrial sales decreased 8.0 percent due to an economic slowdown. Residential and commercial sales increased 6.6 percent and 8.1 percent, respectively, in 2000 due to weather and economic growth. Industrial sales remained fairly constant in 2000.
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:
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2002 Annual Report
2002 2001 2000 -------------------------- Total generation (billions of KWH) 70.4 68.9 73.6 Sources of generation (percent) -- Coal 77.4 74.9 75.8 Nuclear 21.1 23.2 21.2 Hydro 1.2 1.4 0.8 Oil and gas 0.3 0.5 2.2 Average cost of fuel per net KWH generated (cents) -- 1.44 1.38 1.39 - ---------------------------------------------------------------
Fuel expense increased 6.8 percent due to an increase in generation because of higher energy demands and a higher average cost of fuel due to the higher cost of coal in 2002. 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. In 2000, fuel expense increased 10.7 percent due to an increase in generation because of higher energy demands and a slightly higher average cost of fuel.
Purchased power expense decreased $87 million (11.2 percent) in 2002 primarily due to a decrease in off-system purchases used to meet lower off-system sales commitments. This decrease, which had no significant effect on income, was partially offset by a $43 million increase in capacity expense associated with new purchased power contracts. Purchased power expense increased $175 million (29.4 percent) in 2001 primarily due to an increase in off-system purchases used to meet off-system sales commitments. These transactions had no significant effect on earnings. Purchased power expense in 2000 increased $206 million (53.0 percent) over the prior year due to higher retail energy demands and off-system purchase transactions used to meet off-system sales transactions.
In 2002, other operation and maintenance expenses increased $85 million (6.8 percent) due to increased generating plant maintenance, higher transmission expense, and increased property insurance expense. 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. Other operation and maintenance expenses in 2000 increased slightly over the prior year. Increased line maintenance, customer assistance and sales expense, and severance costs were partially offset by decreased generating plant maintenance and decreased employee benefit provisions.
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. Depreciation and amortization increased $66 million in 2000 primarily due to $50 million of additional accelerated amortization of regulatory assets required under the second year of the prior GPSC retail rate order and increased plant in service. See Note 3 to the financial statements under "Retail Rate Orders" for additional information.
Interest expense decreased in 2002 and 2001 primarily due to lower interest rates that offset new financing costs. Interest expense increased in 2000 due to the issuance of additional senior notes. The Company refinanced or retired $929 million, $775 million, and $179 million of securities in 2002, 2001, and 2000, respectively. Interest capitalized decreased in 2002 due to the transfer of three new generation projects to Southern Power. Interest capitalized increased in 2001 and 2000 during the construction phase of these new projects. See Note 4 under "Construction Program" for additional information regarding the construction and subsequent transfer of these generation assets. Distributions on preferred securities of subsidiary companies increased in 2002 due to the issuance of additional securities and remained unchanged in 2001. Distributions on preferred securities of subsidiary companies decreased $7 million in 2000 due to the redemption of $100 million of preferred securities in December 1999.
Other income (expense), net decreased in 2002 due to lower gains realized on sales of assets. Other income (expense), net increased in 2001 due to gains realized on sales of assets and a decrease in charitable contributions. Other income (expense), net decreased in 2000 due to an increase in charitable contributions.
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2002 Annual Report
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 plants 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. The level of future earnings depends on numerous factors including energy sales and regulatory matters.
Growth in energy sales is subject to a number of factors which traditionally have included changes in contracts with neighboring utilities, energy conservation practiced by customers, the price elasticity of demand, weather, competition, initiatives to increase sales to existing customers, and the rate of economic growth in the Company's service area which has decreased recently in concert with a slowing national economy. Retail sales growth assuming normal weather is expected to be 2.3 percent on average from 2003 to 2005 and is down from last year's forecast of 3.1 percent.
The Company currently operates as a vertically integrated utility providing electricity to customers within its traditional service area located in the State of Georgia. Prices for electricity provided by the Company to retail customers are set by the GPSC under cost-based regulatory principles.
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 $59 million in 2002. Future pension income is dependent on several factors including trust earnings and changes to the plan. Current estimates indicate a reversal of recording pension income to recording pension expense by as early as 2006. Postretirement benefit costs for the Company were $43 million in 2002 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 the Company, pension income and postretirement benefit costs are a component of the regulated rates and do not have a significant effect on net income. For additional information, see Note 2 to the financial statements.
In December 2001, the GPSC approved a three-year retail rate order for the Company ending December 31, 2004. Under the terms of the order, earnings will be 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 will be applied to rate refunds with the remaining one-third retained by the Company. Retail rates were decreased by $118 million effective January 1, 2002. Pursuant to a previous three-year accounting order, the Company recorded $333 million of accelerated cost amortization and interest thereon which has been credited to a regulatory liability account as mandated by the GPSC. Under the rate order, the accelerated amortization and the interest will be amortized equally over three years as a credit to expense beginning in 2002. Within the three year period covered by the rate order, the Company may not file for a general base rate increase unless its projected retail return on common equity falls below 10 percent. 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. See Note 3 to the financial statements under "Retail Rate Orders" for additional information.
Beginning in 2002, the Company entered into purchased power agreements which will result in higher capacity and operating and maintenance payments in future years. Under the current retail rate order, these costs will be reflected in rates evenly over the three years ending 2004. In December 2002, the GPSC approved additional expansion of the Company's electricity generating capacity starting in 2005 through purchased power contracts. Beginning in June 2005, the Company will purchase 1,040 megawatts of capacity from the planned units at Plant McIntosh to be built and owned by Southern Power, and will also buy 620 megawatts of capacity from a plant owned by Duke Energy Trading & Marketing. See Note 4 to the financial statements under "Purchased Power Commitments" for additional information. Additionally, the GPSC approved the retirement of 415 megawatts from 11 units at plants Arkwright, Atkinson, and Mitchell. The
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retirements are the result of a unit retirement analysis that determined the units are more expensive to operate than the cost of replacement power. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost - together with the cost of removal, less salvage - is charged to accumulated depreciation.
On December 24, 2002, the GPSC approved an order allowing Georgia Power to implement a natural gas and oil procurement and hedging program effective January 1, 2003. This order allows the Company to use financial instruments in implementing a hedging program. 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 Georgia Power retaining 25 percent of the net gains.
Georgia Power had three generation projects under construction during 2001. They included two units at Plant Dahlberg, a ten-unit, 800 megawatt combustion turbine facility; two units totaling 1,132 megawatts at Plant Wansley; and Plant Franklin (formerly Plant Goat Rock), a two-unit, 1,181 megawatt facility. All three of these projects have been transferred, at cost, 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.
See Note 3 to the financial statements for information regarding material litigation issues that could possibly affect future earnings.
Compliance costs related to current and future environmental laws, regulations, and litigation could affect earnings if such costs are not fully recovered. See "Environmental Matters" for further discussion of these matters.
The State of Georgia is currently considering changes to laws that could potentially impact Georgia Power's ability to establish sites for new transmission lines. The proposed legislation would require certification by the GPSC prior to the acquisition of any property for the construction of an electric transmission line. The outcome of this matter cannot now be determined.
Proposed nuclear security legislation is expected to be introduced in the 108th Congress. The Nuclear Regulatory Commission (NRC) is also considering additional security measures for licensees that could require immediate implementation. Any such requirements could have a significant impact on the Company's nuclear power plants and result in increased operation and maintenance expenses as well as additional capital expenditures. The impact of any new requirements would depend upon the development and implementation of the regulations.
Industry Restructuring
The electric utility industry in the United States is continuing to evolve as a result of regulatory and competitive factors. Among the primary agents of change was the Energy Policy Act of 1992 (Energy Act). The Energy Act allows independent power producers (IPPs) to access a utility's transmission network in order to sell electricity to other utilities. This enhanced the incentive for IPPs to build power plants for a utility's large industrial and commercial customers where retail access is allowed and sell energy to other utilities. Also, electricity sales for resale rates were affected by numerous new energy suppliers, including power marketers and brokers.
This past year, merchant energy companies and traditional electric utilities with significant energy marketing and trading activities came 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.
Although the Energy Act does not provide for retail customer access, it has been a major catalyst for recent restructuring and consolidations taking 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
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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. 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.
Continuing to be a low-cost producer could provide opportunities to increase market share and profitability in markets that evolve with changing regulation and competition. Conversely, 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.
FERC Matters
In December 1999, the Federal Energy Regulatory Commission (FERC) issued its final rule on Regional Transmission Organizations (RTOs). The order encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Southern Company has submitted a series of status reports informing the FERC of progress toward the development of a Southeastern RTO. In these status reports, Southern Company explained that it is developing a for-profit RTO known as SeTrans with a number of non-jurisdictional cooperative and public power entities. In 2002, the sponsors of SeTrans established a Stakeholder Advisory Committee, which will participate in the development of the RTO, and held public meetings to discuss the SeTrans proposal. On October 10, 2002, the FERC granted Southern Company's and other SeTrans sponsors' petition for a declaratory order regarding the governance structure and the selection process for the Independent System Administrator (ISA) of the SeTrans RTO. The FERC also provided guidance on other issues identified in the petition. The SeTrans sponsors announced the selection of ESB International, Ltd. (ESBI) to be the preferred candidate for ISA. Should negotiations with this candidate successfully conclude with final agreement among the parties, the SeTrans sponsors intend to seek any state and federal regulatory or other approvals necessary for the formation of the SeTrans RTO and the approval of ESBI to serve in the capacity of SeTrans ISA. The creation of SeTrans is not expected to have a material impact on the Company's financial statements; however, the outcome of this matter 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 a day ahead and spot energy markets; and (7) revise the FERC policy on the pricing of transmission expansions. Comments on certain aspects of the proposal have been submitted by Southern Company. Any impact of this proposal on the Company will depend on the form in which final rules may be ultimately adopted; however, the Company's revenues, expenses, assets, and liabilities could be adversely affected by changes in the transmission regulatory structure in its regional power market.
Accounting Policies
Critical Policy
Georgia Power's significant accounting policies are described in Note 1 to the financial statements. The Company's only critical accounting policy involves rate regulation. The Company is subject to the provisions of FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of the Company's operations is no longer subject to these provisions, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable and determine if any other assets, including plant, have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
New Accounting Standards
Derivatives - -----------
Effective January 2001, Georgia Power adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. In October 2002, the Emerging Issues Task Force (EITF) of the FASB announced accounting changes related to energy trading contracts in Issue No. 02-03. In October 2002, the Company prospectively adopted the EITF's requirements to reflect the impact of certain energy trading contracts on a net basis. This change had no material
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impact on the Company's income statement. Another change also required certain energy trading contracts to be accounted for on an accrual basis effective January 2003. This change had no impact on the Company's current accounting treatment.
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, establishes 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 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 non-regulated companies 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 "Regulatory Assets and Liabilities" and "Depreciation and Nuclear Decommissioning."
Guarantees - ----------
In 2002, the FASB issued Interpretation No. 45, Accounting and Disclosure Requirements for Guarantees. This interpretation requires disclosure of certain direct and indirect guarantees, as reflected in Note 4 to the financial statements under "Guarantees." Also, the interpretation requires recognition of a liability at inception for certain new or modified guarantees issued after December 31, 2002. The adoption of Interpretation No. 45 in January 2003 did not have a material impact on the Company's financial statements.
FINANCIAL CONDITION
Plant Additions
In 2002, gross utility plant additions were $884 million. These additions were primarily related to transmission and distribution facilities, the purchase of nuclear fuel and equipment to comply with environmental standards. The funds needed for gross property additions are currently provided from operations, short-term and long-term debt, and capital contributions from Southern Company. The Statements of Cash Flows provide additional details.
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. At December 31, 2002, the maximum potential collateral requirements were approximately $229 million.
Exposure to Market Risks
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, 2002 was 1.7 percent. If the Company sustained a 100 basis point change in interest rates for all variable rate long-term debt, the change would affect annualized interest expense by approximately $9 million. To further 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. See Note 1 and Note 9 to the financial statements under "Financial Instruments" for additional information. 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 entered into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market and to a lesser extent similar contracts for gas purchases. Realized gains and losses are recognized in the Statements of Income as incurred. At December 31, 2002 and 2001, exposure
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from these activities was not material to the Company's financial statements. Fair value of changes in derivative energy contracts and year-end valuations were as follows:
Changes in Fair Value - ---------------------------------------------------------------- 2002 2001 - ---------------------------------------------------------------- (in millions) Contracts beginning of year $0.4 $0.9 Contracts realized or settled 0.9 (0.6) New contracts at inception - - Changes in valuation techniques - - Current period changes (1.2) 0.1 ================================================================ Contracts end of year $0.1 $0.4 ================================================================
All of these contracts are actively quoted and mature within one year. For additional information, see Note 1 to the financial statements under "Financial Instruments."
Gains (losses) were not material and were recognized in income in 2002 and 2001. The Company is exposed to market-price risk in the event of nonperformance by parties 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 9 to the financial statements under "Financial Instruments."
Financing Activities
In 2002, the Company's financing costs decreased due to lower interest rates despite the issuance of new debt during the year. New issues during 2000 through 2002 totaled $2.6 billion and retirement or repayment of higher-cost securities totaled $1.9 billion.
The 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. Subsequent to December 31, 2002, the Company has issued $250 million of new securities with the proceeds being used primarily to retire current maturities and to reduce short-term debt. An additional $150 million of securities has been issued to retire long-term debt and for other corporate purposes.
The proceeds from assets transferred to Southern Power were used to reduce short-term debt and return capital that was used during the construction of these projects to Southern Company.
Composite financing rates for long-term debt, preferred stock, and preferred securities for the years 2000 through 2002, as of year-end, were as follows:
2002 2001 2000 ------------------------------- Composite interest rate on long-term debt 4.47% 4.26% 5.90% Composite preferred stock dividend rate 4.60 4.60 4.60 Composite preferred securities dividend rate 6.35 7.49 7.49 - ---------------------------------------------------------------
Liquidity and Capital Requirements
Cash provided from operating activities of $1.2 billion increased by $142 million primarily due to lower fuel inventories and the collection of underrecovered fuel costs. See the Statements of Cash Flows for additional information.
The Company plans investments primarily in additional transmission and distribution facilities and equipment to comply with environmental requirements. In addition to the funds needed for the construction program, capital will be needed for lease commitments and fuel and purchased power contracts. For additional information, see Note 4 to the financial statements.
Also, capital will be needed for the maturities of long-term debt. The Company will continue to retire higher-cost debt and preferred securities and replace these obligations with lower-cost capital if market conditions permit. For additional information, see Note 9 to the financial statements under "Securities Due Within One Year."
As a result of requirements by the NRC, the Company has established external trust funds for nuclear decommissioning costs. For additional information concerning nuclear decommissioning costs, see Note 1 to the financial statements under "Depreciation and Nuclear Decommissioning."
As discussed in Note 2, the Company also provides postretirement benefits to substantially all employees and funds trusts to the extent required by the GPSC and the FERC.
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The liquidity and capital requirements discussed above are as follows:
2003 2004 2005 - ------------------------------------------------------------------- (in millions) Construction expenditures $ 759 $ 781 $806 Senior and other notes 320 0 150 Leases Capital 2 2 2 Operating 30 28 23 Purchase commitments Fuel 1,097 764 657 Purchased power 223 285 389 Trusts Nuclear decommissioning 9 9 9 Postretirement benefits 8 9 8 - -------------------------------------------------------------------
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 and equity securities, term loans, and short-term borrowings. The Company received new financing authority from the GPSC in early 2002, which allows for the issuance of new long-term securities.
Recently, the Company has relied on the issuance of unsecured debt and trust preferred securities, in addition to unsecured pollution control bonds issued for its benefit by public authorities, to meet its long-term external financing requirements. To meet short-term cash needs and contingencies, the Company had approximately $1.175 billion of unused credit arrangements with banks at the beginning of 2003. See Note 9 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. At December 31, 2002, the Company had outstanding $358 million of commercial paper and $19 million of extendible commercial notes.
In February 2002, the Company defeased its first mortgage bond indenture. As a result, the Company cannot issue any securities pursuant to the first mortgage bond indenture. Any liens or encumbrances on the Company's property pursuant to the first mortgage bond indenture were discharged. See "First Mortgage Bond Indenture" under Note 9 to the financial statements for more information.
At the beginning of 2003, Georgia Power had not used any of its available credit arrangements. Bank credit arrangements are as follows:
Expires --------------------- Total Unused 2003 ------------------------------------------------ (in millions) $1,175 $1,175 $1,175 - --------------------------------------------------
All of these credit arrangements allow for the execution of term loans for an additional two year period.
Environmental Matters
New Source Review Enforcement Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action in U.S. District Court in Georgia. The complaint alleges violations of the New Source Review 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 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.
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 complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal-burning plants constructed or under construction prior to 1978. As directed by the court, the EPA refiled its amended complaint limiting claims to those brought against the Company.
The case against the Company has been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the
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Tennessee Valley Authority (TVA). The TVA appeal involves many of the same legal issues raised by the actions against the Company. Because the outcome of the TVA appeal could have a significant adverse impact on Georgia Power, the Company has been a party to that case as well. On August 21, 2002, the U.S. District Court in Georgia denied the EPA's motion to reopen the Georgia case. The denial was without prejudice to the EPA to refile the motion at a later date, which the EPA has not done 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. An adverse outcome in any one of these cases 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 Clean Air Act 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 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 (HAPS) 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 January 27, 2003, Georgia Power filed a response to the complaint. Georgia Power also filed a motion to dismiss the allegations regarding emission offsets and HAPS. 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.
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, a major portion of which is expected to be recovered through existing ratemaking provisions. 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. Compliance was required in two phases -- Phase I, effective in 1995 and Phase II, effective in 2000. Construction expenditures associated with Phase I and Phase II compliance totaled approximately $206 million.
Some of the expenditures required to comply with the Phase II acid rain requirements 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 has adopted regulations that will require additional nitrogen oxide emission reductions from plants in and/or near those nonattainment areas, beginning in May 2003. Seven generating plants in the Atlanta area will be affected. Construction expenditures for compliance with these new rules are currently estimated at approximately $690 million, of which $71 million remains to be spent.
To help bring the remaining nonattainment areas into compliance with the one-hour ozone standard, in 1998 the EPA issued regional nitrogen oxide reduction rules. Those rules required 21 states, including Georgia, to reduce and cap nitrogen oxide emissions from power plants and other large industrial sources. For Georgia, the EPA must complete a separate rulemaking before the requirements will apply. The EPA proposed a rule for Georgia in 2002 and expects to issue a final rule in 2003. The proposed rule requires compliance by May 1, 2005.
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.
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Supreme Court found the EPA's implementation program for the new ozone standard unlawful and remanded it to the EPA for further rulemaking. The EPA is expected to propose implementation rules designed to address the court's concerns in 2003 and issue final implementation rules in 2004. The remaining legal challenges to the new standards, which were pending before the U.S. Court of Appeals, District of Columbia Circuit, have been resolved.
The EPA plans to designate areas as attainment or nonattainment with the new eight-hour ozone standard by April 2004, based on air quality data for 2001 through 2003. Several areas within the Company's service territory are likely to be designated nonattainment under the new ozone standard. State implementation plans, including new emission control regulations necessary to bring those areas into attainment, could be required as early as 2007. Those state plans 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.
The EPA currently plans to designate areas as attainment or nonattainment with the new fine particulate matter standard by the end of 2004. Those area designations will be based on air quality data collected during 2001 through 2003. Several areas within the Company's service territory will likely be designated nonattainment under the new particulate matter standard. State implementation plans, including new emission control regulations necessary to bring those areas into attainment, could be required as early as the end of 2007. Those state plans will likely require reductions in sulfur dioxide emissions from power plants. If so, the reductions could be required sometime after 2007. Any additional emission reductions and costs associated with the new fine particulate matter standard cannot be determined at this time.
The EPA has also announced plans to issue a proposed Regional Transport Rule for the fine particulate matter standard by the end of 2003 and to finalize the rule in 2005. This rule would likely require year-round sulfur dioxide and nitrogen oxide emission reductions from power plants as early as 2010. If issued, this rule would likely modify other state implementation plan requirements for attainment of the fine particulate matter standard and the eight-hour ozone standard. It is not possible at this time to determine the effect such a rule would have on the Company.
Further reductions in sulfur dioxide 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 regional haze program calls for states to submit State Implementation Plans in 2007 and 2008 that contain emission reduction strategies for achieving progress toward the visibility improvement goal. In 2002, however, the U.S. Court of Appeals, District of Columbia Circuit, vacated and remanded the BART provisions of the federal Regional Haze rules to the EPA for further rulemaking. Because new BART rules have not been developed and state visibility assessments 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 be applying for renewal of its Title V operating permits between 2003 and 2005, and a number of its 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, which could indicate a need for improved particulate matter controls at affected facilities. Because the plans are still in the early stages of development, the Company cannot determine the extent to which improved controls could be required or the costs associated with any necessary improvements. Actual ongoing monitoring costs are expensed as incurred and are not material for any period presented.
In December 2000, having completed its utility studies for mercury and other HAPS, the EPA issued a determination that an emission control program for mercury and, perhaps, other HAPS is warranted. The program is being developed under the Maximum Achievable Control Technology provisions of the Clean Air Act. The EPA currently plans to issue proposed rules regulating mercury emissions from electric utility boilers by the end of 2003, and those regulations are
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scheduled to be finalized by the end of 2004. Compliance could be required as early as 2007. Because the rules have not yet been proposed, the costs associated with compliance cannot be determined at this time.
In December 2002, the EPA issued final and proposed revisions to the New Source Review program under the Clean Air Act. In February 2003, several northeastern states petitioned the D.C. Circuit Court for a stay of the final rules. The proposed rules are open to public comment and may be revised before being finalized by the EPA. If fully implemented, these proposed and final regulations could affect the applicability of the New Source Review provisions to activities at the Company's facilities. In any event, any final regulations must be adopted by the State of Georgia in order to apply to the Company's facilities. The effect of these proposed and final rules cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent emissions limitations have been proposed. Three of these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2002, and the Clean Air Planning Act of 2002, proposed to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills also proposed to limit emissions of carbon dioxide. None of these bills were enacted into law in the last Congress. Similar bills have been, and are anticipated to be, introduced this year. The Bush Administration's Clear Skies Act was recently reintroduced, and President Bush has stated that it will be a high priority for the Administration. Other bills already introduced include the Climate Stewardship Act of 2003, which proposes capping greenhouse gas emissions. The cost impacts of such legislation would depend upon the specific requirements enacted.
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 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. As part of Southern Company, the Company is involved in a voluntary electric utility industry sector climate change initiative in partnership with the government. Because this initiative is still under development, it is not possible to determine the effect on the Company at this time.
The Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous 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. The Company expensed $4.0 million, $0.6 million, and $4.0 million for cleanup and ongoing monitoring costs in 2002, 2001, and 2000, respectively. 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 "Other Environmental Contingencies" for information regarding the Company's potentially responsible party status at sites in Georgia.
Under the Clean Water Act, the EPA is developing new rules aimed at reducing impingement and entrainment of fish and fish larvae at cooling water intake structures that will require numerous biological studies, and, perhaps, retrofits to some intake structures at existing power plants. The new rule was proposed in February 2002 and will be finalized by August 2004. The impact of any new standards will depend on the development and implementation of applicable regulations.
Also, under the Clean Water Act, the EPA and the State of Georgia Environmental Protection Division 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Georgia Power Company 2002 Annual Report
The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including limits on pollutant discharges to impaired waters, hazardous waste disposal requirements, and other regulatory matters. The impact of any new standards 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.
Compliance with possible additional federal or state legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could also significantly affect the Company. The impact of any new legislation, or changes to existing legislation, could affect many areas of the Company's operations. The full impact of any such changes cannot be determined at this time.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
The Company's 2002 Annual Report includes forward-looking statements in addition to historical information. Forward-looking information includes, among other things, statements concerning retail sales growth expectations. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "predicts," "projects," "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 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 and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations; current and future litigation, including the pending EPA civil action; the effect, extent, and timing of the entry of additional competition in the markets in which the Company operates; the impact of fluctuations in commodity prices, interest rates, and customer demand; state and federal rate regulations; political, legal, and economic conditions and developments in the United States; the effects of, and changes in economic conditions in the areas in which the Company operates, including the current soft economy; internal restructuring or other restructuring options that may be pursued by the Company; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial; the direct or indirect effects on the Company's business resulting from the terrorist incidents on September 11, 2001, or any similar such incidents or responses to such incidents; financial market conditions and the results of financing efforts; the ability of counterparties of the Company to make payments as and when due; the ability of the Company to obtain additional generating capacity at competitive prices; weather and other natural phenomena; and other factors discussed elsewhere herein and in other reports (including Form 10-K) filed from time to time by the Company with the Securities and Exchange Commission.
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NOTES TO FINANCIAL STATEMENTS Georgia Power Company 2002 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 operating companies, Southern Power Company (Southern Power), a system service company (SCS), Southern Communications Services (Southern LINC), Southern Company Gas (Southern GAS), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The 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 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. SCS provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern GAS, which began operation in August 2002, is a competitive retail natural gas marketer serving communities in Georgia. Southern Holdings is an intermediate holding subsidiary for Southern Company's investments in leveraged leases, alternative fuel products, and an energy services business. Southern Nuclear 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 the respective 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 $318 million in 2002, $286 million in 2001, and $266 million in 2000. 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 $301 million in 2002, $281 million in 2001, and $281 million in 2000.
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. Collections from these agreements with Southern Power amounted to $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 4 under "Construction Program" for additional information.
Effective June 2002, the Company entered into purchased power agreements with Southern Power for capacity and energy. Purchased power costs in 2002 amounted to $128 million. Additionally, the Company recorded $12 million of
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prepaid capacity expenses included in Other Deferred Charges and Other Assets on the balance sheet at December 31, 2002. See Note 4 under "Purchased Power Commitments" for additional information.
The Company has an agreement with Gulf Power under which Gulf Power jointly owns a portion of Plant Scherer. Under this agreement, Georgia Power operates Plant Scherer and Gulf Power reimburses the Company for its proportionate share of the related expenses which were $4.5 million in 2002. Georgia Power has an agreement with Savannah Electric under which Georgia Power jointly owns a portion of Plant McIntosh. Under this agreement, Savannah Electric operates Plant McIntosh and Georgia Power reimburses Savannah Electric for its proportionate share of the related expenses which were $1.8 million in 2002. See Note 6 for additional information.
The operating companies, including Georgia Power, Southern Power, and Southern 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 4 under "Fuel Commitments" and "Purchased Power Commitments" for additional information.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. 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:
2002 2001 --------------------- (in millions) Deferred income tax charges $ 525 $ 544 Deferred income tax credits (208) (229) Premium on reacquired debt 179 174 Corporate building lease 54 54 Vacation pay 54 52 Postretirement benefits 25 28 Department of Energy assessments 16 18 Generating plant outage costs 48 24 Accelerated cost recovery (222) (336) Environmental remediation reserve (21) - Purchased power (63) - Other regulatory assets 7 17 Other regulatory liabilities (1) (1) - -------------------------------------------------------------- Total $ 393 $ 345 ==============================================================
See "Depreciation and Nuclear Decommissioning" in this note for information regarding significant regulatory assets and liabilities created as a result of the January 1, 2003 adoption of FASB Statement No. 143, Accounting for Asset Retirement Obligations.
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 exists, including plant, and if impaired, write down the assets to their fair value. All regulatory assets and liabilities are reflected in rates.
Revenues and Fuel Costs
The Company currently 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.
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.
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 fuel cost recovery mechanism includes provisions to adjust revenues for fluctuations in fuel costs, fuel hedging, the energy component of
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purchased power costs, and certain other costs. Revenues are adjusted for differences between recoverable fuel costs and amounts actually recovered in current rates.
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 $71 million in 2002, $75 million in 2001, and $75 million in 2000. The Company has contracts with the U.S. Department of Energy (DOE) that provide for the permanent disposal of used nuclear fuel. The DOE failed to begin disposing of used 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 is available at Plant Vogtle to maintain full-core discharge capability for both units until the year 2014. To maintain pool discharge capability at Plant Hatch, effective June 2000, an on-site dry storage facility for Plant Hatch became operational. Sufficient dry storage capacity is believed to be available to continue dry storage operations at Plant Hatch through the life of the plant. Procurement of on-site dry storage capacity at Plant Vogtle will commence 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 to be funded in part by a special assessment on utilities with nuclear plants. The assessment will be 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 -- based on its ownership interests -- estimates its remaining liability at December 31, 2002 under this law to be approximately $13 million. This obligation is recorded in other deferred credits in the accompanying Balance Sheets.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.9 percent in 2002 and 3.3 percent in 2001 and 2000. 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.
In January 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 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 cost must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life.
There was no cumulative effect adjustment to net income resulting from the adoption of Statement No. 143. The Company received permission from the GPSC to defer the transition adjustment, therefore, the Company recorded a related regulatory asset of $21 million to reflect the regulatory treatment of these costs under Statement No. 71 as of January 2003. The initial Statement No. 143 liability the Company recognized was $469 million, of which $332 million was removed from the accumulated depreciation reserve. The amount capitalized to property, plant, and equipment was $116 million.
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. 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 Georgia Power 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 respective 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.
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It is estimated that this annual difference will be approximately $23 million. Management believes actual asset removal costs will be recoverable in rates over time.
Statement No. 143 does not permit non-regulated companies to continue accruing future retirement costs for long-lived assets they do not have a legal obligation to retire. However, in accordance with the regulatory treatment of these costs, the Company will continue to recognize the removal costs for these other obligations in the depreciation rates. As of January 1, 2003, the amount included in the accumulated depreciation reserve that represents a regulatory liability for these costs was $419 million.
The Company recorded accelerated depreciation and amortization amounting to $91 million in 2001 and $135 million in 2000. Effective January 2002, the Company discontinued recording accelerated depreciation and amortization in accordance with the 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 depreciation and amortization expense beginning January 2002. See Note 3 under "Retail Rate Orders" for additional information.
The Nuclear Regulatory Commission (NRC) regulations require all licensees operating commercial 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. Earnings on the trust funds are considered in determining decommissioning expense. 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.
The Company periodically conducts site-specific studies to estimate the actual cost of decommissioning its nuclear generating facilities. Site study cost is the estimate to decommission the facility as of the site study year, and ultimate cost is the estimate to decommission the facility as of its retirement date. The estimated site study costs based on the most current study and ultimate costs assuming an inflation rate of 4.7 percent for the Company's ownership interests are as follows:
Plant Plant Hatch Vogtle ------------------- Site study year 2000 2000
Decommissioning periods: Beginning year 2014 2027 Completion year 2042 2045 - ------------------------------------------------------------ (in millions) Site study costs: Radiated structures $486 $420 Non-radiated structures 37 48 - ------------------------------------------------------------ Total $523 $468 ============================================================ (in millions) Ultimate costs: Radiated structures $1,004 $1,468 Non-radiated structures 79 166 - ------------------------------------------------------------ Total $1,083 $1,634 ============================================================
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, the NRC requirements, the assumptions used in making the estimates, regulatory requirements, technology, and costs of labor, materials, and equipment.
Annual provisions for nuclear decommissioning expense are based on an annuity method as approved by the GPSC. The amounts expensed in 2002 and fund balances as of December 31, 2002 were:
Plant Plant Hatch Vogtle - ---------------------------------------------------------------- (in millions) Amount expensed in 2002 $7 $2 ================================================================ (in millions) Accumulated provisions: External trust funds, at fair value $219 $128 Internal reserves 7 4 - ---------------------------------------------------------------- Total $226 $132 ================================================================
Effective January 1, 2002, the GPSC decreased the annual provision for decommissioning expenses 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,
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respectively. The ultimate costs associated with the 2000 NRC minimum funding requirements are $823 million and $1.03 billion for plants Hatch and Vogtle, respectively. Significant assumptions 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 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. Decommissioning costs will not reflect the license extension until a new site study is completed in 2003 and the GPSC issues a new rate order, which is not expected until 2004.
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.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized
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. For the years 2002, 2001, and 2000, the average AFUDC rates were 3.79 percent, 6.33 percent, and 6.74 percent, respectively. AFUDC and interest capitalized, net of taxes, as a percentage of net income after dividends on preferred stock, was less than 3.0 percent for 2002, 2001, and 2000.
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 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, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a 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 reevaluated 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.
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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.
Comprehensive Income
Comprehensive income -- consisting 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 -- is presented in the financial statements. 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.
Financial Instruments
The Company uses derivative financial instruments to hedge 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 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 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 are derivatives. However, these contracts qualify as normal purchases and sales and are accounted for under the accrual method. Other contracts qualify as cash flow hedges of anticipated transactions, resulting 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. Contracts that do not qualify for the normal purchase and sale exception and that do not meet the hedge requirements are marked to market through current period income and are recorded on a net basis in the Statements of Income.
The Company's financial instruments for which the carrying amounts did not approximate fair value at December 31 were as follows:
Carrying Fair Amount Value ------------------------ Long-term debt: (in millions) At December 31, 2002 $3,350 $3,417 At December 31, 2001 $3,190 $3,190 Preferred securities: At December 31, 2002 $940 $961 At December 31, 2001 $789 $782 - --------------------------------------------------------------
The fair values for securities were based on either closing market prices or closing prices of comparable instruments.
2. RETIREMENT BENEFITS
The Company has defined benefit, trusteed pension plans that cover substantially all employees. The Company also provides certain non-qualified benefit plans for a selected group of management and highly compensated employees. Also, the Company provides certain medical care and life insurance benefits for retired employees. The Company funds postretirement trusts to the extent required by the GPSC and the FERC. In late 2000, as well as in 2002, the Company adopted several pension and postretirement benefits plan changes that had the effect of increasing benefits to both current and future retirees.
Plan assets consist primarily of domestic and international equities, global fixed income securities, real estate, and private equity investments. The measurement date for plan assets and obligations is September 30 for each year.
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Pension Plan
Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows: Projected Benefit Obligation ------------------------- 2002 2001 - -------------------------------------------------------------- (in millions) Balance at beginning of year $1,448 $1,322 Service cost 36 35 Interest cost 107 101 Benefits paid (74) (74) Amendments 33 - Actuarial loss 14 64 - -------------------------------------------------------------- Balance at end of year $1,564 $1,448 ==============================================================
Plan Assets ------------------------ 2002 2001 - ------------------------------------------------------------- (in millions) Balance at beginning of year $2,044 $2,464 Actual return on plan assets (137) (356) Benefits paid (69) (64) - ------------------------------------------------------------- Balance at end of year $1,838 $2,044 =============================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
2002 2001 - ------------------------------------------------------------- (in millions) Funded status $274 $ 596 Unrecognized transition obligation (17) (22) Unrecognized prior service cost 123 98 Unrecognized net actuarial (loss) (78) (444) - ------------------------------------------------------------- Prepaid asset, net 302 228 Portion included in benefit obligations 40 45 - ------------------------------------------------------------- Total prepaid assets recognized in the Balance Sheets $342 $ 273 =============================================================
In 2002 and 2001, amounts recognized in the Balance Sheets for accumulated other comprehensive income and intangible assets were $13 million and $10 million and $0 and $11 million, respectively.
Components of the plan's net periodic cost were as follows:
2002 2001 2000 - --------------------------------------------------------------- (in millions) Service cost $ 36 $ 35 $ 33 Interest cost 107 101 94 Expected return on plan assets (179) (168) (152) Recognized net gain (27) (31) (26) Net amortization 4 3 (1) - --------------------------------------------------------------- Net pension (income) $ (59) $ (60) $ (52) ===============================================================
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 -------------------------- 2002 2001 - --------------------------------------------------------------- (in millions) Balance at beginning of year $542 $495 Service cost 8 9 Interest cost 40 39 Benefits paid (27) (24) Actuarial loss 64 23 - --------------------------------------------------------------- Balance at end of year $627 $542 ===============================================================
Plan Assets --------------------------- 2002 2001 - ---------------------------------------------------------------- (in millions) Balance at beginning of year $195 $198 Actual return on plan assets (18) (26) Employer contributions 49 47 Benefits paid (27) (24) - ---------------------------------------------------------------- Balance at end of year $199 $195 ================================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows: 2002 2001 - --------------------------------------------------------------- (in millions) Funded status $ (427) $ (347) Unrecognized transition obligation 96 105 Unrecognized prior service cost 98 104 Unrecognized net loss 106 5 Fourth quarter contributions 37 27 - --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $ (90) $(106) ===============================================================
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Components of the plans' net periodic cost were as follows:
2002 2001 2000 - --------------------------------------------------------------- (in millions) Service cost $ 8 $ 9 $ 7 Interest cost 40 39 36 Expected return on plan assets (20) (19) (16) Net amortization 15 14 12 - --------------------------------------------------------------- Net postretirement cost $ 43 $ 43 $ 39 ===============================================================
The weighted average rates assumed in the actuarial calculations for both the pension and postretirement benefit plans were:
2002 2001 2000 - --------------------------------------------------------------- Discount 6.5% 7.5% 7.5% Annual salary increase 4.0 5.0 5.0 Long-term return on plan assets 8.5 8.5 8.5 - ---------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 8.75 percent for 2002, 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, 2002 as follows:
1 Percent 1 Percent Increase Decrease - --------------------------------------------------------------- (in millions) Benefit obligation $59 $52 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 2002, 2001, and 2000 were $17 million, $16 million, and $15 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. The Company's business activities are also 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 currently filed against the Company cannot be predicted at this time; however, after consultation with legal counsel, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on the Company's financial statements.
Retail Rate Orders
In December 2001, the GPSC approved a three-year retail rate order for the Company ending December 31, 2004. Under the terms of the order, earnings will be 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 the Company. The Company's earnings in 2002 were within the common equity range. Retail rates were decreased by $118 million effective January 1, 2002.
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. In 2000, the Company recorded $44 million of revenue subject to refund for estimated earnings above 12.5 percent retail return on common equity. Refunds applicable to 2000 were made to customers in 2001.
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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 rate order, the accumulated accelerated amortization and the interest are being amortized equally over three years as a credit to expense beginning in 2002. Effective January 1, 2002, the Company discontinued recording accelerated depreciation and amortization. Within the three-year period covered by the rate order, the Company may not file for a general base rate increase unless its projected retail return on common equity falls below 10 percent. 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.
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 Georgia Power to implement a natural gas and oil procurement and hedging program. This order allows the Company to use financial instruments in implementing a hedging program. 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 hedging program will be shared with the retail customers receiving 75 percent and Georgia Power retaining 25 percent of the net gains.
New Source Review Enforcement Actions
In November 1999, the EPA brought a civil action in U.S. District Court in Georgia. The complaint alleges violations of the New Source Review 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 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.
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 complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal-burning plants constructed or under construction prior to 1978. As directed by the court, the EPA refiled its amended complaint limiting claims to those brought against the Company.
The case against the Company has been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA appeal involves many of the same legal issues raised by the actions against the Company. Because the outcome of the TVA appeal could have a significant adverse impact on Georgia Power, the Company has been a party to that case as well. On August 21, 2002, the U.S. District Court in Georgia denied the EPA's motion to reopen the Georgia case. The denial was without prejudice to the EPA to refile the motion at a later date, which the EPA has not done 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. 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 financial condition if such costs are not recovered through regulated rates.
Plant Wansley Clean Air Act 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 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
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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 January 27, 2003, Georgia Power filed a response to the complaint. Georgia Power also filed a motion to dismiss the allegations regarding emission offsets and hazardous air pollutants. 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.
Other Environmental Contingencies
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. Georgia Power has recognized $34 million in cumulative expenses through December 31, 2002 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, 2002, 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 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.
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.
The GPSC has approved a performance award of approximately $7.8 million for performance during the 1996-1998 period. This award was collected through the retail fuel cost recovery provision and recognized in income over a 36-month period that began in January 2000 as mandated by the GPSC.
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 period.
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 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, Southern Company Energy Solutions, a subsidiary of Southern Company, was named a defendant.
In October 2001, the district court denied 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 United States 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 plaintiff's claims. The
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parties await the district court's ruling on the seven motions for summary judgment. The final outcome of this matter cannot now be determined.
Right of Way Litigation
In 2002, Georgia Power was named as a defendant in several lawsuits brought by landowners 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 plaintiffs' claims are without merit. An adverse outcome could result in substantial judgments; however, the final outcome of these matters cannot now be determined.
4. COMMITMENTS
Construction Program
Significant construction of transmission and distribution facilities and projects to remain in compliance with environmental requirements will continue. The Company currently estimates property additions to be approximately $759 million, $781 million, and $806 million in 2003, 2004, and 2005, respectively. 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, 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, 2002, significant purchase commitments were outstanding in connection with the construction program.
Georgia Power 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.
In connection with the transfer of plants Dahlberg, Franklin, and Wansley, the Company has assigned $12 million in vendor equipment contracts to Southern Power. While the Company could be obligated to assume responsibility for these contracts if Southern Power fails to meet these commitments, Southern Company has entered into limited keep-well arrangements whereby Southern Company would contribute funds to Southern Power either through loans or capital contributions in order to fund performance by Southern Power as equipment purchaser under certain contingencies. Southern Company has also guaranteed Southern Power obligations totaling $6.7 million for the Company's construction of transmission interconnection facilities to these plants.
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. Total estimated long-term fossil and nuclear fuel commitments at December 31, 2002 were as follows: Minimum Year Obligations - ---- ------------------ (in millions) 2003 $1,097 2004 764 2005 657 2006 564 2007 465 2008 and beyond 1,236 - ----------------------------------------------------------- Total $4,783 ===========================================================
Additional commitments for coal and for nuclear fuel will be required to supply the Company's future needs.
In addition, SCS acts as agent for the five operating companies, Southern Power, and Southern GAS with regard to natural gas purchases. Natural gas purchases (in dollars) are based on various indices at the actual time of delivery; therefore, only the volume commitments are firm and disclosed in the following chart. The committed volumes, as of December 31, 2002, are as follows:
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Year Natural Gas - ---- ------------------- (MMBtu) 2003 18,588,990 2004 17,306,665 2005 17,143,446 2006 12,785,477 2007 4,587,102 - ------------------------------------------------------------ Total 70,411,680 ============================================================
Purchased Power Commitments
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:
2002 2001 2000 --------------------------------- (in millions) Energy $53 $52 $57 Capacity 32 30 30 - -------------------------------------------------------------- Total $85 $82 $87 ==============================================================
The Company has commitments regarding a portion of a 5 percent interest in Plant Vogtle owned by Municipal Electric Authority of Georgia (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, $59 million, and $58 million in 2002, 2001, and 2000, respectively. The current projected Plant Vogtle capacity payments are:
Year Capacity Payments - ---- ---------------------- (in millions) 2003 $ 59 2004 57 2005 56 2006 54 2007 54 2008 and beyond 423 - ---------------------------------------------------------------- Total $ 703 ================================================================
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 was written off in 1987 and 1990.
The Company has entered into other various long-term commitments for the purchase of electricity. Estimated total long-term capacity obligations at December 31, 2002 were as follows:
Non- Year Affiliateed Affiliated - ---- ---------------------------- (in millions) 2003 $ 123 $ 41 2004 183 45 2005 255 78 2006 268 86 2007 268 87 2008 and beyond 1,800 564 - -------------------------------------------------------------- Total $2,897 $ 901 ==============================================================
Acting as an agent for all of Southern Company's operating companies, Southern Power, and Southern GAS, SCS may enter into various types of wholesale energy and natural gas contracts. Each of the operating companies, Southern Power, and Southern GAS may be jointly and severally liable under these agreements. The creditworthiness of Southern Power and Southern GAS is currently inferior to the creditworthiness of the operating companies. Southern Company has entered into keep-well agreements with each of the 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 GAS as a contracting party under these agreements.
Operating Leases
The Company has entered into various operating leases with various terms and expiration dates. Rental expenses related to these operating leases totaled $35
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million for 2002, $14 million for 2001, and $16 million for 2000. At December 31, 2002, estimated minimum rental commitments for these noncancelable operating leases were as follows:
Minimum Obligations Year Rail Cars Other Total - ---- -------------------------------------- (in millions) 2003 $ 14 $ 16 $ 30 2004 14 14 28 2005 12 11 23 2006 13 8 21 2007 12 8 20 2008 and beyond 67 23 90 - --------------------------------------------------------------- Total $ 132 $ 80 $ 212 ===============================================================
In addition to the rental commitments above, the Company has obligations upon expiration of certain of the 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 railcar lease obligations is shared with the joint owners of plants Scherer and Wansley. Rental expenses related to the railcar 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, 2002, the outstanding loans guaranteed by the Company were $14 million and loan loss reserves of $3.4 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 principal amount of pollution control revenue bonds are outstanding. Georgia Power has agreed to reimburse Alabama Power for the pro rata portion of such obligation corresponding to Georgia Power's then proportionate ownership of stock of SEGCO if Alabama Power is called upon to make such payment under its guaranty.
As discussed earlier in this note under "Operating Leases," the Company has entered into certain residual value guarantees related to rail car leases.
5. 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 $9.5 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 $88 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 $178 million per incident but not more than an aggregate of $20 million to be paid for each incident in any one year.
The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members' nuclear generating facilities.
Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 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 between 8 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. Georgia Power 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 three NEIL policies would be $40 million.
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NOTES (continued) Georgia Power Company 2002 Annual Report
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 terrorist acts. The NEIL aggregate, which applies to all claims stemming from terrorism within a 12 month duration, is $3.24 billion plus any amounts that would be available through reinsurance or indemnity from an outside source. The ANI cap is a $300 million shared industry aggregate.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies should 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.
6. JOINT OWNERSHIP AGREEMENTS
Except as otherwise noted, the Company has contracted to operate and maintain all jointly owned generating facilities. 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 (FP&L), Jacksonville Electric Authority (JEA), 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.
The Company includes its proportionate share of plant operating expenses in the corresponding operating expenses in the Statements of Income.
At December 31, 2002, 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% $3,267 $1,779 Plant Hatch (nuclear) 50.1 884 665 Plant Wansley (coal) 53.5 305 156 Plant Scherer (coal) Units 1 and 2 8.4 113 58 Unit 3 75.0 554 234 Plant McIntosh Common Facilities 75.0 24 3 (combustion-turbine) Rocky Mountain 25.4 169 82 (pumped storage) Intercession City 33.3 12 1 (combustion-turbine) - --------------------------------------------------------------------
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the other operating companies of Southern Company, except Savannah Electric, have long-term contractual agreements for the sale of capacity and energy to certain non-affiliated utilities located outside the system's service area. These agreements consist of firm unit power sales pertaining to capacity from specific generating units. Because energy is generally sold at cost under these agreements, it is primarily the capacity revenues that affect the Company's profitability.
The Company's capacity revenues were as follows:
Year Revenues Capacity ------------------------------------- (in millions) (megawatts) 2002 $34 102 2001 26 102 2000 30 124 -------------------------------------
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NOTES (continued) Georgia Power Company 2002 Annual Report
Unit power from specific generating plants is being sold to FP&L, FPC, and JEA. Under these agreements, approximately 103 megawatts of capacity is scheduled to be sold annually for periods after 2002 with a minimum of three years notice until the expiration of the contracts in 2010.
8. INCOME TAXES
At December 31, 2002, tax-related regulatory assets were $525 million and tax-related regulatory liabilities were $208 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:
2002 2001 2000 ------------------------------- Total provision for income taxes: (in millions) Federal: Current $261 $352 $342 Deferred 60 (46) (34) - ----------------------------------------------------------------- 321 306 308 - ----------------------------------------------------------------- State: Current 31 61 48 Deferred 5 (8) (5) Deferred investment tax credits - 5 10 - ----------------------------------------------------------------- Total $357 $364 $361 ===============================-=================================
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:
2002 2001 ------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $1,779 $1,722 Property basis differences 623 660 Other 309 295 - ----------------------------------------------------------------- Total 2,711 2,677 - ----------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 90 88 Other property basis differences 170 178 Other deferred costs 214 257 Other 64 40 - ----------------------------------------------------------------- Total 538 563 - ----------------------------------------------------------------- Net deferred tax liabilities 2,173 2,114 Portion included in current assets 3 50 - ---------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $2,176 $2,164 ================================================================
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 $12 million in 2002 and $15 million in both 2001 and 2000. At December 31, 2002, 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:
2002 2001 2000 ------------------------- Federal statutory rate 35% 35% 35% State income tax, net of federal deduction 2 4 4 Non-deductible book depreciation 1 2 2 Other (1) (4) (2) - -------------------------------------------------------------- Effective income tax rate 37% 37% 39% ==============================================================
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 Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability.
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NOTES (continued) Georgia Power Company 2002 Annual Report
9. CAPITALIZATION
First Mortgage Bond Indenture
In 2002, the first mortgage bond indenture of Georgia Power 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.
Preferred Securities
Statutory trusts formed by the Company, of which the Company owns all the common securities, have issued mandatorily redeemable preferred securities. The following securities are currently outstanding:
Date of Maturity Issue Amount Rate Notes Date --------------------------------------------------------- (millions) % (millions)
Trust IV 2/1999 $200 6.850 $206 3/2029 Trust V 6/2002 440 7.125 454 3/2042 Trust VI 11/2002 300 4.875* 309 11/2042
* Issued at a five year initial fixed rate of 4.875 percent and, thereafter, at fixed rates determined through remarketings for specific periods of varying length or at floating rates determined by reference to 3-month LIBOR plus 3.05 percent.
The securities issued by Trusts I, II, and III were redeemed in 2002.
Substantially all of the assets of each trust are junior subordinated notes issued by the Company in the respective approximate principal amounts set forth above.
The Company considers that the mechanisms and obligations relating to the preferred securities, taken together, constitute a full and unconditional guarantee by the Company of the Trusts' payment obligations with respect to the preferred securities.
The Trusts are subsidiaries of the Company and accordingly are consolidated in the Company's financial statements.
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, 2002 was $1.7 billion.
Senior Notes
In 2002, the Company issued a total of $500 million of unsecured senior notes. The proceeds of these issues were used to redeem higher cost long-term debt and to reduce short-term borrowing.
Bank Credit Arrangements
At the beginning of 2003, the Company had unused credit arrangements with banks totaling $1.175 billion expiring at April 18, 2003. Upon expiration, the $1.175 billion 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 portions of the commitments or the maintenance of 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. An annual fee is also paid to the agent bank.
The credit arrangements contain covenants that limit the level of indebtedness to capitalization to 65 percent. Not meeting these limits would result in an event of default under the credit arrangements. In addition, the credit arrangements contain cross default provisions to other indebtedness of the Company that would trigger an event of default if the Company defaulted on indebtedness over a specified threshold. The Company is currently in compliance with all such covenants.
This $1.175 billion 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, 2002 was $422 million. In addition, the Company borrows under uncommitted lines of credit with banks, through a $155 million extendible commercial note program, and through a $750 million commercial paper program that has the liquidity support of the committed bank credit arrangements. The amount of extendible commercial notes and commercial paper outstanding at
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NOTES (continued) Georgia Power Company 2002 Annual Report
December 31, 2002 was $19 million and $358 million, respectively. The amount of commercial paper outstanding at December 31, 2001 was $708 million. Commercial paper is included in notes payable on the Balance Sheets.
Financial Instruments
The Company enters into interest rate swaps to hedge exposure to interest rate changes. Swaps related to fixed rate securities are accounted for as fair value hedges. Swaps related to variable rate securities or forecasted transactions are accounted for as cash flow hedges. The swaps are generally structured to mirror the terms of the hedged debt instruments; therefore, no material ineffectiveness has been recorded in earnings. The gain or loss in fair value for cash flow hedges is recorded in other comprehensive income and will be recognized in earnings over the life of the hedged items. In 2002, the Company recognized gains totaling $413 thousand upon settlement of certain cash flow hedges.
At December 31, 2002, the Company had interest rate swaps outstanding with net deferred losses as follows:
Cash Flow Hedges
Weighted Average Variable Fixed Fair Rate Rate Notional Value Maturity Received Paid Amount (Loss) - --------------------------------------------------------------- (in millions) 2003 * 4.76% $250 $(7) *Rate has not been set
Other Long-Term Debt
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, 2002 and 2001, the Company had a capitalized lease obligation for its corporate headquarters building of $81 million 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, 2002 and 2001, the interest and lease amortization deferred on the Balance Sheets was $54 million.
Securities 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:
2002 2001 ------------------ (in millions) Capital lease $ 2 $ 2 First mortgage bonds - 2 Pollution control bonds - 8 Senior notes 320 300 - --------------------------------------------------------------- Total $322 $312 ===============================================================
Serial maturities through 2007 applicable to total long-term debt are as follows: $322 million in 2003; $2 million in 2004; $153 million in 2005; $153 million in 2006; and $303 million in 2007.
10. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial information for 2002 and 2001 is as follows:
Net Income After Operating Operating Dividends on Quarter Ended Revenues Income Preferred Stock - --------------------------------------------------------------------- (in millions) -------------------------------------------- March 2002 $ 1,007 $260 $127 June 2002 1,204 320 171 September 2002 1,517 498 271 December 2002 1,095 126 49
March 2001 $ 1,108 $249 $ 108 June 2001 1,259 322 163 September 2001 1,579 515 298 December 2001 1,020 126 41 - ---------------------------------------------------------------------
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 2002 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 system of internal accounting controls is 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 five independent directors, provides a broad overview of management's financial reporting and control functions. Additionally, a committee of Gulf Power'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 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/Thomas A. Fanning Thomas A. Fanning President and Chief Executive Officer
/s/Ronnie R. Labrato Ronnie R. Labrato Vice President, Chief Financial Officer and Comptroller February 17, 2003
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INDEPENDENT AUDITORS' REPORT
Gulf Power Company:
We have audited the accompanying balance sheet and statement of capitalization of Gulf Power Company (a wholly owned subsidiary of Southern Company) as of December 31, 2002, and the related statements of income, comprehensive income, common stockholders' equity, and cash flows for the year 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 audit. The financial statements of Gulf Power Company as of December 31, 2001, and for each of the two years then ended 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 audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the 2002 financial statements (pages II-152 to II-170) present fairly, in all material respects, the financial position of Gulf Power Company at December 31, 2002, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
/s/Deloitte & Touche LLP February 17, 2003 Atlanta, Georgia
THE FOLLOWING REPORT OF INDEPENDENT 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 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-129 through 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.
/s/Arthur Andersen LLP
Atlanta, Georgia February 13, 2002 II-138
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Gulf Power Company 2002 Annual Report
RESULTS OF OPERATIONS
Earnings
Gulf Power Company's 2002 net income after dividends on preferred stock was $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 2000. In 2000, earnings were $51.8 million, down $1.9 million when compared with the prior year. The improvement in earnings in 2002 is due primarily to higher operating revenues related to an increase in base rates, offset somewhat by higher operating expenses and higher financing costs primarily related to the commercial operation of Plant Smith Unit 3 in April 2002. The increase in 2001 earnings was primarily a result of an increase in Allowance for Funds Used During Construction (AFUDC) and lower interest expense. The decrease in 2000 earnings was primarily a result of expenses related to the discontinuance of the Company's appliance sales division and higher interest expense. A condensed income statement follows:
Increase (Decrease) Amount From Prior Year - --------------------------------------------------------------- 2002 2002 2001 2000 - --------------------------------------------------------------- (in millions) Operating revenues $820 $ 95 $ 11 $40 - --------------------------------------------------------------- Fuel 274 73 (15) 7 Purchased power 63 (44) 24 26 Other operation and maintenance 200 23 5 - Depreciation and amortization 77 9 1 2 Taxes other than income taxes 61 6 (1) 4 - --------------------------------------------------------------- Total operating expenses 675 67 14 39 - --------------------------------------------------------------- Operating income 145 28 (3) 1 Other income and (expense) (41) (13) 10 (5) Income taxes (37) (6) - 2 - --------------------------------------------------------------- Net income $ 67 $ 9 $ 7 $ (2) ===============================================================
Revenues
Operating revenues increased in 2002 when compared to 2001 and 2000. The following table summarizes the changes in operating revenues for the past three years:
2002 2001 2000 ----------------------------------- (in thousands) Retail - Prior Year $584,591 $548,640 $516,949 Change in - Base Revenues 31,200 - (8,508) Sales Growth 16,557 10,254 4,407 Weather 9,497 (5,699) 7,522 Fuel and other cost recovery 23,991 31,396 28,270 - ----------------------------------------------------------------- Total retail 665,836 584,591 548,640 - ----------------------------------------------------------------- Sales for resale-- Non-affiliates 77,171 82,252 66,890 Affiliates 40,391 27,256 66,995 - ----------------------------------------------------------------- Total sales for resale 117,562 109,508 133,885 Other operating revenues 37,069 31,104 31,794 - ----------------------------------------------------------------- Total operating revenues $820,467 $725,203 $714,319 ================================================================= Percent change 13.1% 1.5% 6.0% - -----------------------------------------------------------------
Retail revenues increased $81.2 million, or 13.9 percent in 2002, $36.0 million, or 6.6 percent in 2001, and $31.7 million, or 6.1 percent in 2000. The significant factors driving these changes are shown in the table above. In addition, 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 plus 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 $117.6 million in 2002, an increase of $8.1 million, or 7.4 percent, from 2001 primarily due to increased energy sales for resale to affiliates reflecting the commercial operation of the 574 MW Plant Smith Unit 3.
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2002 Annual Report
Sales for resale were $109.5 million in 2001, a decrease of $24.4 million, or 18.2 percent, from 2000 and $133.9 million in 2000, an increase of $5.4 million, or 4.2 percent over 1999. 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.
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:
2002 2001 2000 ----------------------------------- (in thousands) Unit Power -- Capacity $19,898 $19,472 $20,270 Energy 28,565 27,579 21,922 - ------------------------------------------------------------- Total $48,463 $47,051 $42,192 =============================================================
Capacity revenues remained relatively unchanged during 2002, 2001, and 2000. No significant declines in the amount of capacity are scheduled until the termination of these contracts in 2010. See Note 6 to the financial statements for additional information.
Other operating revenues for 2002 increased $6.0 million due primarily to a $1.7 million settlement related to a power purchase agreement, a $3.3 million increase in franchise fees, and $0.9 million increase in revenues from the transmission of electricity to others.
Energy Sales
Kilowatt-hour sales for 2002 and the percent changes by year were as follows:
KWH Percent Change ------------------------------------------ 2002 2002 2001 2000 ------------------------------------------ (millions) Residential 5,144 9.1% (1.5)% 7.1% Commercial 3,553 4.0 1.2 4.9 Industrial 2,054 1.8 4.8 4.3 Other 21 - 10.5 - ------- Total retail 10,772 5.9 0.6 5.8 Sales for resale Non-affiliates 2,157 3.1 22.8 9.2 Affiliates 1,720 78.4 (49.8) (23.7) ------- Total 14,649 10.7 (3.7) 0.7 ==================================================================
The retail energy sales increases in 2002 and 2000 were primarily due to the impact of weather on the residential and commercial sectors. An increase in energy sales for resale to non-affiliates of 3.1 percent in 2002, 22.8 percent in 2001, and 9.2% in 2000, 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. 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 2002 increased $67.0 million, or 11 percent, over the amount recorded in 2001 due primarily to higher fuel and maintenance costs. In 2001, total operating expenses increased $13.5 million, or 2.3 percent, compared to 2000 due primarily to higher purchased power expenses and maintenance expenses. In 2000, total operating expenses increased $39.5 million, or 7.1 percent, from the prior year due primarily to higher fuel and purchased power expenses.
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. In 2000, fuel expenses increased $6.7 million, or 3.2 percent, as a result of an increase in average fuel costs.
The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated were as follows:
2002 2001 2000 ------------------------------ Total generation (millions of kilowatt-hours) 13,142 11,423 12,866 Sources of generation (percent) Coal 81.8 99.0 98.2 Gas 18.2 1.0 1.8 Average cost of fuel per net kilowatt-hour generated (cents)-- 2.08 1.76 1.68 - ------------------------------------------------------------- ----------
Purchased power expenses decreased in 2002 by $43.2 million, or 40.7 percent, from 2001 primarily due to a decrease in purchased power from non-affiliated companies. This decrease in expenses from non-affiliates is mainly attributable
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2002 Annual Report
to additional generating capacity within the Southern system in 2002 including the Company's Plant Smith Unit 3. Purchased power expenses for 2001 increased from 2000 by $23.8 million, or 28.8 percent, due primarily to an increase in purchased power from affiliate companies. Purchased power expenses for 2000 increased by $25.5 million, or 44.7 percent, due primarily to a higher demand for energy.
Purchases of energy from affiliates will vary from year to year depending on demand and the availability and cost of generating resources at each company. These purchases have little impact on earnings.
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 in April 2002. Depreciation and amortization expense increased $1.3 million, or 2.0 percent, in 2001 and $2.3 million, or 3.5 percent, in 2000 due to an increase in depreciable property. The increases in 2001 and 2000 were also due to the amortization of a portion of a regulatory asset, which was allowed in the current retail revenue sharing plan. See Note 3 to the financial statements under "Retail Revenue Sharing Plan" for further information.
Allowance for equity funds used during construction in 2002 was $3.0 million due primarily to the completion of Plant Smith Unit 3, which began construction in 2000. See Note 1 to the financial statements under "Allowance for Funds Used During Construction and Interest Capitalized" for further information.
Interest expense increased $6.4 million, or 25.6 percent, in 2002 due primarily to the issuance of $60 million of senior notes in August 2001, $75 million of senior notes in October 2001, and $45 million of senior notes in January 2002. These financings 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. In 2000, interest expense increased $1.2 million, or 4.6 percent, due primarily to the issuance of $50 million of senior notes in August 1999.
Effects of Inflation
The Company is subject to rate regulation based on the recovery of historical costs. In addition, the income tax laws are 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.
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. The major factors include regulatory matters and the ability to achieve energy sales growth.
Future earnings in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. Traditionally, these factors have included the rate of economic growth in the Company's service area, weather, competition, changes in contracts with neighboring utilities, the elasticity of demand, and energy conservation practiced by the Company's customers.
The Company currently operates as a vertically integrated utility providing electricity to customers within its traditional service area located in northwest Florida. Prices for electricity provided by the Company to retail customers are set by the Florida Public Service Commission (FPSC).
In September 2001 the Company filed a request with the FPSC for a base rate increase of approximately $70 million, the majority of which was related to the Plant Smith Unit 3 combined cycle facility which was placed in service in April 2002. In May 2002 the FPSC approved a retail base rate increase of $53.2 million effective June 7, 2002.
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2002 Annual Report
In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash pre-tax pension income of approximately $5.6 million in 2002. Future pension income is dependent on several factors including trust earnings and changes to the plan. Current estimates indicate a reversal of recording pension income to recording pension expense as early as 2006. Postretirement benefit costs for the Company were $4.5 million in 2002 and are expected to continue to trend upward. A portion of pension income and postretirement benefit costs are capitalized based on construction-related labor charges. For more information regarding pension and postretirement benefits, see Note 2 to the financial statements.
The Company is involved in various matters being litigated. See Note 3 to the financial statements for information regarding material issues that could possibly affect future earnings.
Compliance costs related to current and future environmental laws and regulations could affect earnings if such costs are not fully recovered. The Clean Air Act and other important environmental items are discussed later in Financial Condition under "Environmental Matters." Also, Florida legislation adopted in 1993 and amended in 2002 provides for recovery of prudent environmental compliance costs and is discussed in Note 3 to the financial statements under "Environmental Cost Recovery."
Industry Restructuring
The electric utility industry in the United States is continuing to evolve as a result of regulatory and competitive factors. Among the primary agents of change was the Energy Policy Act of 1992 (Energy Act). The Energy Act allows independent power producers (IPPs) to access a utility's transmission network in order to sell electricity to other utilities. This enhances the incentive for IPPs to build power plants for a utility's large industrial and commercial customers where retail access is allowed and sell energy to other utilities. Also, electricity sales for resale rates were affected by numerous new energy suppliers, including power marketers and brokers.
This past year merchant energy companies and traditional electric utilities with significant energy marketing and trading activities came 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).
Although the Energy Act does not provide for retail customer access, it has been a major catalyst for recent restructuring and consolidations taking place within the utility industry. Numerous federal and state initiatives to 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 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.
In 2000, Florida's Governor appointed a study commission to look at the state's electric industry, studying issues ranging from 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, they will have to be drafted and voted into law by the Legislature. No legislation of this type was voted on in 2002. 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.
Continuing to be a low-cost producer could provide opportunities to increase market share and profitability in markets that evolve with changing regulation.
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2002 Annual Report
Conversely, 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.
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 staff of the legislature's Joint Administrative Procedures Committee (JAPC) has filed a letter with the FPSC that raises some concerns with the proposed rule. The FPSC cannot file the rule for adoption until JAPC's comments have been addressed, therefore, the effective date for this new rule has not yet been established.
The FPSC, in collaboration with the Florida Department of Environmental Protection (FDEP), was directed by the Florida Legislature to prepare a report on renewable energy. A final report was prepared by the FPSC and FDEP in January 2003. This report describes various renewable and green energy options. The report provided the FPSC, the FDEP, and the state 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 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 non-by-passable public benefits charge by the State could add additional costs to the Company's operations and affect the Company's competitive position.
FERC Matters
In December 1999, the FERC issued its final rule on Regional Transmission Organizations (RTOs). The order encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Southern Company has submitted a series of status reports informing the FERC of progress toward the development of a Southeastern RTO. In these status reports, Southern Company explained that it is developing a for-profit RTO known as SeTrans with a number of non-jurisdictional cooperative and public power entities. In 2001, Entergy Corporation and Cleco Power joined the SeTrans development process. In 2002, the sponsors of SeTrans established a Stakeholder Advisory Committee, which will participate in the development of the RTO, and held public meetings to discuss the SeTrans proposal. On October 10, 2002, the FERC granted Southern Company's and other SeTrans sponsors' petition for a declaratory order regarding the governance structure and the selection process for the Independent System Administrator (ISA) of the SeTrans RTO. The FERC also provided guidance on other issues identified in the petition. The SeTrans sponsors announced the selection of ESB International, Ltd. (ESBI) to be the preferred ISA candidate. Should negotiations with this candidate successfully conclude with final agreement among the parties, the SeTrans sponsors intend to seek any state and federal regulatory or other approvals necessary for formation of the SeTrans RTO and the approval of ESBI to serve in the capacity of the SeTrans ISA. The creation of SeTrans is not expected to have a material impact on the Company's financial statements; however, the outcome of this matter 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 a day ahead and spot energy markets;
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2002 Annual Report
and (7) revise the FERC policy on the pricing of transmission expansions. Comments on certain aspects of the proposal have been submitted by Southern Company. Any impact of this proposal on the Company will depend on the form in which final rules may be ultimately adopted; however the Company's revenues, expenses, assets, and liabilities could be adversely affected by changes in the transmission regulatory structure in its regional power market.
Accounting Policies
Critical Policy
The Company's significant accounting policies are described in Note 1 to the financial statements. The Company's only critical accounting policy involves rate regulation. The Company is subject to the provisions of FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of the Company's operations is no longer subject to these provisions, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable, and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
New Accounting Standards
Derivatives
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. In October 2002, the Emerging Issues Task Force (EITF) of the FASB announced accounting changes related to energy trading contracts in Issue No. 02-3. In October 2002, the Company prospectively adopted the EITF's requirement to reflect the impact of certain energy trading contracts on a net basis. This change had no material impact on the Company's income statement. Another change also required certain energy trading contracts to be accounted for on an accrual basis effective January 2003. This change had no impact on the Company's current accounting treatment.
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 establishes new accounting and reporting standards for legal obligations associated with the ultimate cost of retiring long-lived assets. The present value of 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 non-regulated companies to continue accruing future retirement costs for long-lived assets that the Company does 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 "Regulatory Assets and Liabilities" and "Depreciation and Amortization."
Guarantees
In November 2002, the FASB issued Interpretation No. 45, Accounting and Disclosure Requirements for Guarantees. This interpretation requires disclosure of certain direct and indirect guarantees as reflected in Note 4 to the financial statements. In addition, it requires recognition of a liability at inception for any new or modified guarantees issued after December 31, 2002. The adoption of this new standard had no material impact on the Company's financial statements.
FINANCIAL CONDITION
Overview
During 2002, gross property additions were $106.6 million. Funds for the Company's property additions were provided by operating activities, capital contributions, and additional financings. See the Statements of Cash Flows for additional information.
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.
Exposure to Market Risks
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
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2002 Annual Report
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 rate on variable long-term debt outstanding at December 31, 2002 was 1.43 percent. If the Company sustained a 100 basis point change in interest rates for all variable rate long-term debt, the change would affect annualized interest expense by approximately $0.83 million at December 31, 2002. See Note 1 to the financial statements for additional information. 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 and, to a lesser extent, similar contracts for gas purchases. At December 31, 2002, exposure from these activities was not material. The fair value of changes in derivative energy trading contracts and year-end valuations are as follows:
Changes in Fair Value - -------------------------------------------------------------- 2002 2001 - -------------------------------------------------------------- (in thousands) Contracts beginning of year $(110) $110 Contracts realized or settled 150 (100) New contracts at inception - - Changes in valuation techniques - - Current period changes 2,296 (120) - -------------------------------------------------------------- Contracts end of year $2,336 $(110) ==============================================================
Source of Year-End Valuation Prices - -------------------------------------------------------- Total Maturity Fair Value -------------------- Year 1 1-3 Years - -------------------------------------------------------------- (in thousands) Actively quoted $2,336 $3,176 $(840) External sources - - - Models and other methods - - - - -------------------------------------------------------------- Contracts end of year $2,336 $3,176 $(840) ==============================================================
Unrealized gains and losses from mark to market adjustments on contracts related to 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 contracts that do not represent hedges are recognized in the income statement as incurred. At December 31, 2002, the fair value of derivative energy contracts was reflected in the financial statements as follows:
Amounts - --------------------------------------------------------------- (in thousands) Regulatory liabilities, net $2,322 Other comprehensive income - Net income 14 - --------------------------------------------------------------- Total fair value $2,336 ===============================================================
Approximately $0.12 million and $0.05 million of gains were recognized in income in 2002 and 2001, respectively. The Company is exposed to market-price risk in the event of nonperformance by parties 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 its counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments."
Financing Activities
In 2002, the Company issued $45 million of Senior Notes primarily to finance certain construction costs for Plant Smith Unit 3. Also in 2002, the Company refinanced a total of $55 million of pollution control bonds. In 2001, the Company sold $135 million of senior notes and $30 million of trust preferred securities and used the proceeds to retire $30 million of first mortgage bonds and for Plant Smith Unit 3 construction. Composite financing rates for the years 2000 through 2002 as of year end were as follows:
2002 2001 2000 ----------------------------- Composite interest rate on long-term debt 5.3% 5.6% 6.2% Composite rate on trust preferred securities 6.9% 7.2% 7.3% Composite preferred stock dividend rate 5.1% 5.1% 5.1% - -----------------------------------------------------------------
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2002 Annual Report
The composite interest rates on long-term debt decreased in 2002 due to the refinancing of certain pollution control bonds at lower interest rates. The composite rate on trust preferred securities decreased in 2002 due to refinancing the 7.625% issue with flexible trust preferred securities at a five year initial fixed rate of 5.60%.
Capital Requirements for Construction
The Company's gross property additions, including those amounts related to environmental compliance, are budgeted at $414 million for the three years beginning in 2003 ($108 million in 2003, $150 million in 2004, and $156 million in 2005). These amounts include $34 million, $52 million, and $47 million in 2003, 2004, and 2005, respectively, for capital expenditures related to environmental controls at Plant Crist as part of an agreement with the FDEP to reduce nitrogen oxide (NOx) emissions. The FPSC authorized the Company to recover the costs related to these environmental projects through the Environmental Cost Recovery Clause. See further discussion under Environmental Matters and Note 4 to the financial statements under "Construction Program." The remaining capital expenditures are for maintaining and upgrading transmission and distribution facilities and generating plants. 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.
Other Capital Requirements
The Company will continue to retire higher-cost debt and preferred securities and replace these securities with lower-cost capital as market conditions and terms of the instruments permit.
Future note maturities, operating lease obligations, and purchase commitments - discussed in notes 4 and 8 to the financial statements - are as follows:
2003 2004 2005 - ---------------------------------------------------------------- (in millions) Notes 60 50 0 Operating leases 2 2 2 - ---------------------------------------------------------------- Purchase commitments Fuel 113 90 92 Purchased power 1 1 1 - -------------------------------------------------------------- Long-term service agreements 7 7 7 - --------------------------------------------------------------
Environmental Matters
New Source Review Enforcement 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 alleges violations of the New Source Review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. 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 operating companies a notice of violation related to ten generating facilities, including the five facilities mentioned previously and the Company's Plants Crist and Scherer. For additional information, see Note 5 to the financial statements under "Joint Ownership Agreements" related to the Company's ownership interest in Georgia Power's Plant Scherer Unit No. 3.
In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation, and to add the Company, Mississippi Power, and Savannah Electric as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities had failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. 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
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2002 Annual Report
nor operated the generating units involved in the proceedings. The court granted the EPA's motion to add Savannah Electric as a defendant, but denied the motion to add the Company and Mississippi Power based on lack of jurisdiction. As directed by the court, the EPA re-filed its amended complaint limiting claims to those brought against Georgia Power and Savannah Electric. The EPA also re-filed its claims against Alabama Power in the U.S. District Court in Alabama. It has not re-filed against the Company, Mississippi Power, or SCS.
The Alabama Power, Georgia Power, and Savannah Electric cases have been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA appeal involves many of the same legal issues raised against Alabama Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA appeal could have a significant adverse impact on Alabama Power and Georgia Power, both companies have been parties to that case as well. In February 2003, the U.S. District Court in Alabama extended the stay of the EPA litigation proceeding in Alabama until the earlier of May 6, 2003, or a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the related litigation involving TVA. On August 21, 2002, the U.S. District Court in Georgia denied the EPA's motion to reopen the Georgia case. The denial was without prejudice to the EPA to refile the motion at a later date, which the EPA has not done 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 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, a major portion of which is expected to be recovered through existing ratemaking provisions. There is no assurance, however, that all such costs will, in fact, be recovered.
Compliance with the federal Clean Air Act and resulting regulations have 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. Compliance was required in two phases -- Phase I, effective in 1995 and Phase II, effective in 2000. Construction expenditures associated with Phase I totaled approximately $42 million for the Company. Phase II sulfur dioxide compliance was required in 2000 and did not have a material impact on the Company.
In 1993, the Florida Legislature 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. This legislation was amended in 2002 to allow specific recovery of costs incurred as a result of an agreement between the Company and the FDEP for the purpose of ensuring compliance with ozone ambient air quality standards adopted by the EPA. 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.
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 ozone standard unlawful and remanded it to the EPA for further rulemaking. The EPA is expected to propose implementation rules designed to address the court's concerns in 2003 and issue final implementation rules in 2004. The remaining legal challenges to the new standards, which were pending before the U.S. Court of Appeals, District of Columbia Circuit, have been resolved.
Based on recommendations from the State, EPA is expected to designate areas of Florida as attainment or nonattainment for the new ozone and particulate standards in April 2004. In August 2002, the Company entered into an agreement
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2002 Annual Report
with the FDEP calling for 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 Crist Unit 7 by 2005. In addition, the Company will retire Crist Unit 1 in 2003 and Units 2 and 3 by 2006. Costs for implementation of the agreement have been approved for recovery under the Environmental Cost Recovery Clause.
The EPA has also announced plans to issue a proposed Regional Transport Rule for the fine particulate matter standard by the end of 2003 and to finalize the rule in 2005. This rule would likely require year-round sulfur dioxide and nitrogen oxide emission reductions from power plants as early as 2010. It is not possible at this time to determine the effect such a rule would have on the Company.
Further reductions in sulfur dioxide 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 regional haze program calls for states to submit State Implementation Plans in 2007 and 2008 that contain emission reduction strategies for achieving progress toward the 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. Because new BART rules have not been developed and state visibility assessments 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 be applying for renewal of its Title V operating permits between 2003 and 2005, and a number of the 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, which could indicate a need for improved particulate matter controls at affected facilities. Because the plans are still in the early stages of development, the Company cannot determine the extent to which improved controls could be required or the costs associated with any necessary improvements. Actual ongoing monitoring costs are expensed as incurred and are not material for any period presented.
In December 2000, having completed its utility studies for mercury and other hazardous air pollutants (HAPS), the EPA issued a determination that an emission control program for mercury and, perhaps, other HAPS is warranted. The program is being developed under the Maximum Achievable Control Technology provisions of the Clean Air Act. The EPA currently plans to issue proposed rules regulating mercury emissions from electric utility boilers by the end of 2003, and those regulations are scheduled to be finalized by the end of 2004. Compliance could be required as early as 2007. Because the rules have not yet been proposed, the costs associated with compliance cannot be determined at this time.
In December 2002, the EPA issued final and proposed revisions to the New Source Review program under the Clean Air Act. In February 2003, several northeastern states petitioned the D.C. Circuit Court for a stay of the final rules. The proposed rules are open to public comment and may be revised before being finalized by the EPA. If fully implemented, these proposed and final regulations could affect the applicability of the New Source Review provisions to activities at the Company's facilities. In any event, any final regulations must be adopted by the states in the Company's service area in order to apply to the Company's facilities. The effect of these proposed and final rules cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent emissions limitations have been proposed. Three of these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2002, and the Clean Air Planning Act of 2002 proposed to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills also proposed to limit emissions of carbon dioxide. None of these bills were enacted into law in the 107th Congress. Similar bills have been, and are anticipated to be introduced this year. The Bush Administration's Clear Skies Act was recently
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2002 Annual Report
reintroduced and President Bush has stated that it will be a high priority for the Administration. Other bills already introduced include the Climate Stewardship Act of 2003, which proposes capping greenhouse gas emissions. The cost impacts of such legislation would depend upon the specific requirements enacted.
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 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. Because this initiative is still under development, it is not possible to determine the effect on the Company at this time.
The Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties; however, such costs are expected to be recovered through the Environmental Cost Recovery Clause. 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. The Company expensed $1.2 million, $1.2 million, and $1.3 million for cleanup and ongoing monitoring in 2002, 2001, and 2000, respectively. The Company may be liable for a portion or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements for further information.
Under the Clean Water Act, the EPA is developing new rules aimed at reducing impingement and entrainment of fish and fish larvae at cooling water intake structures that will require numerous biological studies and, perhaps, retrofits to some intake structures at existing power plants. The new rule was proposed in February 2002 and will be finalized by August 2004. The impact of any new standards will depend on the development and implementation of applicable regulations.
Also, 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 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.
The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including limits on pollutant discharges to impaired waters, hazardous waste disposal requirements, and other regulatory matters. The impact of any new standards 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.
Compliance with possible additional federal or state legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could also significantly affect the Company. The impact of any new legislation, or changes to existing legislation, could affect many areas of the Company's operations. The full impact of any such changes cannot be determined at this time.
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2002 Annual Report
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 internal sources. 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 trust preferred securities.
To meet short-term cash needs and contingencies, the Company has various internal and external sources of liquidity. At the beginning of 2003, the Company had approximately $13.3 million of cash and cash equivalents and unused committed lines of credit with banks to meet its short-term cash needs. In addition, the Company has significant cash flow from operating activities.
At the beginning of 2003, the Company had used none of its available credit arrangements. Bank credit arrangements are as follows:
Expires --------------------------- Total Unused 2003 2004 & beyond - --------------------------------------------------------------- (in millions) $66.3 $66.3 $66.3 $ - - ---------------------------------------------------------------
See Note 8 to the financial statements under "Bank Credit Arrangements" and the Statements of Cash Flows 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. At December 31, 2002, the Company had outstanding $8.5 million of commercial paper.
The Company historically has relied on issuances of first mortgage bonds and preferred stock, in addition to pollution control bonds issued for its benefit by public authorities, to meet its long-term external financing requirements. The Company has no restrictions on the amounts of unsecured indebtedness it may incur. However, in order to issue first mortgage bonds or preferred stock, the Company is required to meet certain coverage requirements specified in its mortgage indenture and corporate charter. The Company's ability to satisfy all coverage requirements is such that it could issue new first mortgage bonds and preferred stock to provide sufficient funds for all anticipated requirements.
Cautionary Statement Regarding Forward-Looking Information
The Company's 2002 Annual Report contains forward looking and historical information. Forward looking information includes, among other things, statements concerning projected retail sales growth and scheduled completion of new generation. 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 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 and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations; current and future litigation; the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates; the impact of fluctuations in commodity prices, interest rates, and customer demand; state and federal rate regulations; political, legal, and economic conditions and developments in the United States; internal restructuring or other restructuring options that may be pursued; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company; the ability of counterparties of the Company to make payments as and when due; the effects of, and changes in, economic conditions in the areas in which the Company operates, including the current soft economy; the direct or indirect effects on the Company's business resulting from the terrorist incidents on September 11, 2001, or any similar such incidents or responses to such incidents; financial market conditions and the results of financing
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued) Gulf Power Company 2002 Annual Report
efforts; the ability of the Company to obtain additional generating capacity at competitive prices; weather and other natural phenomena; and other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed from time to time by the Company with the Securities and Exchange Commission.
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NOTES TO FINANCIAL STATEMENTS Gulf Power Company 2002 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 operating companies, Southern Power Company (Southern Power), a system service company (SCS), Southern Communications Services (Southern LINC), Southern Company Gas (Southern GAS), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsi diaries. The operating companies - Alabama Power, Georgia Power, the Company, Mississippi Power, and Savannah Electric - provide electric service in four southeastern states. Southern Power was established in 2001 to construct, own, and manage Southern Company's competitive generation assets and sell electricity at market-based rates in the wholesale market. Contracts among the 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 provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber and cable services within the southeast. Southern GAS, which began operation in August 2002, is a competitive retail natural gas marketer serving customers in Georgia. Southern Holdings is an intermediate holding subsidiary for Southern Company's investments in leveraged leases, alternative fuel products, and an energy services business. Southern Nuclear 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 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 respective 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 $49 million, $45 million, and $44 million during 2002, 2001, and 2000, respectively. Cost allocation methodologies used by SCS are approved by the SEC and management believes they are reasonable.
The operating companies (including the Company), Southern Power, and Southern 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 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 $4.5 million and Mississippi Power $16.6 million in 2002 for its proportionate share of related expenses. See Note 4 under "Lease Agreements" and Note 5 for additional information.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues to the Company
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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 the following:
2002 2001 ------------------------ (in thousands) Deferred income tax charges $ 18,798 $ 16,766 Deferred loss on reacquired debt 14,052 14,518 Environmental remediation 14,428 7,163 Vacation pay 5,044 4,725 Accumulated provision for property damage (15,418) (13,565) Deferred income tax credits (29,692) (28,293) Fuel-hedging liabilities (2,322) - Other regulatory assets 2,859 2,272 Other regulatory liabilities (3,277) (5,245) - ----------------------------------------------------------------- Total $ 4,472 $ (1,659) =================================================================
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 any impairment to other assets, including plant, and write down the assets, if impaired, to their fair value. All regulatory assets and liabilities are reflected in rates.
See "Depreciation and Amortization" for information regarding regulatory assets and liabilities created as a result of the January 1, 2003 adoption of FASB Statement No. 143, Accounting for Asset Retirement Obligations.
Revenues, Regulatory Cost Recovery Clauses, 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. 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.
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.9 percent in 2002, 3.7 percent in 2001, and 3.8 percent in 2000. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost - together with the cost of removal, less salvage - is charged to the accumulated provision for depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Prior to January 2003, in accordance with regulatory requirements, 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 January 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 present value of ultimate costs 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.
There was no cumulative effect adjustment to net income resulting from the adoption of Statement No. 143. The Company expects to receive an accounting order from the FPSC to defer the transition adjustment; therefore, the Company recorded a related regulatory asset of $0.9 million to reflect the Company's regulatory treatment of these costs under Statement No. 71. The initial Statement No. 143 liability the Company recognized was $4.0 million, of which $1.9 million was removed from the accumulated depreciation reserve. The amount capitalized to property, plant, and equipment was $1.2 million.
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NOTES (continued) Gulf Power Company 2002 Annual Report
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, a liability for the removal of these transmission and distribution 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 their 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. It is estimated that this annual difference will be approximately $0.1 million. Management believes that the actual removal costs will be recoverable in rates over time.
Statement No. 143 does not permit non-regulated companies to continue accruing future retirement costs for long-lived assets they do not have a legal obligation to retire. However, in accordance with the regulatory treatment of these costs, the Company will continue to recognize the removal costs for these other obligations in their depreciation rates. As of January 1, 2003, the amount included in the accumulated depreciation reserve that represents a regulatory liability for these costs was approximately $143 million.
Allowance for Funds Used During Construction and Interest Capitalized
In accordance with regulatory treatment, the Company records Allowance for Funds Used During Construction (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 2002, 2001, and 2000 the average AFUDC rates were 7.35 percent, 7.35 percent, and 7.27 percent, respectively. AFUDC, net of taxes, as a percentage of net income after dividends on preferred stock was 5.72 percent, 11.86 percent, and 0.83 percent, respectively for, 2002, 2001, and 2000.
Income Taxes
The Company uses the liability method of accounting for 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.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost. 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.
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 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.
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NOTES (continued) Gulf Power Company 2002 Annual Report
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities and are measured at fair value. Substantially all of the Company's bulk energy purchases and sales contracts are derivatives. However, in many cases, these contracts qualify as normal purchases and sales and are accounted for under the accrual method. Other 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. Contracts that do not qualify for the normal purchase and sale exception and that do not meet the hedge requirements 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 did not equal fair value at December 31 were as follows:
Carrying Fair Amount Value --------------------------- (in thousands) Long-term debt: At December 31, 2002 $512,040 $531,133 At December 31, 2001 $467,784 $474,911 Capital trust preferred securities: At December 31, 2002 $155,000 $156,853 At December 31, 2001 $115,000 $114,898 - --------------------------------------------------------------
The fair values for long-term debt and preferred securities were based on either closing market prices or closing prices of comparable instruments.
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.
Comprehensive Income
Comprehensive income - consisting of net income and changes in additional minimum pension liability, net of income taxes - is presented in the financial statements. 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.
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 expense of settling claims is charged to a provision account. The accumulated provision of $0.7 million and $1.3 million at December 31, 2002 and 2001, respectively, is included in other current liabilities in the accompanying Balance Sheets. For further information see Note 3 under "Personal Injury Litigation."
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NOTES (continued) Gulf Power Company 2002 Annual Report
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, 2002 and 2001, the accumulated provision for property damage was $15.5 million and $13.6 million respectively, and is included in other deferred credits 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 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 $3.5 million in 2002, $4.5 million in 2001, and $3.5 million in 2000 to the accumulated provision for property damage. The Company had a net charge of $1.6 million to the provision account in 2002 and had a net credit of $(0.3) million to the provision account in 2001 related to insurance proceeds that exceeded actual claims. In 2000, the Company charged $0.3 million to the provision account.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, non-contributory pension plan that covers substantially all regular employees. The Company also provides certain non-qualified benefit plans for a selected group of management and highly compensated employees. The Company provides certain medical care and life insurance benefits for retired employees. Substantially all employees may become eligible for these benefits when they retire. Trusts are funded to the extent required by the Company's regulatory commissions. In late 2000, as well as 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.
Plan assets consist primarily of domestic and international equities, global fixed income securities, real estate, and private equity investments. The measurement date for plan assets and obligations is September 30 for each year.
The weighted average rates assumed in the actuarial calculations for both the pension plan and postretirement benefits plan were:
2002 2001 2000 - ------------------------------------------------------------------ Discount 6.50% 7.50% 7.50% Annual salary increase 4.00% 5.00% 5.00% Long-term return on plan assets 8.50% 8.50% 8.50% - ------------------------------------------------------------------
Pension Plan
Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows: Projected Benefit Obligations --------------------------- 2002 2001 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $169,251 $153,214 Service cost 4,910 4,703 Interest cost 12,394 11,644 Benefits paid (8,395) (8,105) Actuarial (gain)/loss and employee transfers, net 2,672 (195) Amendments - 7,997 Other 4,155 (7) - -------------------------------------------------------------- Balance at end of year $184,987 $169,251 ==============================================================
Plan Assets --------------------------- 2002 2001 - --------------------------------------------------------------- (in thousands) Balance at beginning of year $233,706 $283,266 Actual return on plan assets (15,694) (40,841) Benefits paid (7,934) (7,758) Employee transfers 1,088 (961) - --------------------------------------------------------------- Balance at end of year $211,166 $233,706 ===============================================================
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The accrued pension costs recognized in the Balance Sheets were as follows:
2002 2001 - ------------------------------------------------------------- (in thousands) Funded status $26,179 $64,455 Unrecognized transition obligation (2,161) (2,832) Unrecognized prior service cost 14,874 11,689 Unrecognized net gain (6,589) (47,038) 4th quarter cash flow adjustment 85 90 - ------------------------------------------------------------- Prepaid asset, net 32,388 26,364 Portion included in benefit obligations 3,910 3,616 - ------------------------------------------------------------- Total Prepaid asset recognized in the Balance Sheets $36,298 $29,980 =============================================================
In 2002 amounts recognized in the Balance Sheets for accumulated other comprehensive income and intangible assets were $1.2 million and $0.9 million. In 2001, the amount recognized for intangible assets was $1.2 million.
Components of the pension plan's net periodic cost were as follows:
2002 2001 2000 - ---------------------------------------------------------------- Service cost $ 4,910 $ 4,703 $ 4,367 Interest cost 12,394 11,644 10,695 Expected return on plan assets (20,431) (19,312) (17,504) Recognized net gain (2,746) (3,072) (2,582) Net amortization 298 165 (235) - ---------------------------------------------------------------- Net pension income $ (5,575) $ (5,872) $ (5,259) ===============================================================
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 ------------------------- 2002 2001 - ------------------------------------------------------------- (in thousands) Balance at beginning of year $54,337 $50,025 Service cost 948 983 Interest cost 3,992 3,886 Benefits paid (1,984) (1,823) Amendments - 3,412 - ------------------------------------------------------------- Actuarial (gain)/loss 6,382 (2,146) - ------------------------------------------------------------- Balance at end of year $63,675 $54,337 =============================================================
Plan Assets ----------------------- 2002 2001 - ----------------------------------------------------------- (in thousands) Balance at beginning of year $11,632 $13,388 Actual return on plan assets (793) (1,830) Employer contributions 2,038 1,897 Benefits paid (1,984) (1,823) - ----------------------------------------------------------- Balance at end of year $10,893 $11,632 ===========================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows:
2002 2001 - ------------------------------------------------------------- (in thousands) Funded status $(52,782) $(42,705) Unrecognized transition obligation 3,656 4,012 Unrecognized prior service cost 5,349 5,695 Unrecognized net loss 9,530 1,235 Fourth quarter contributions 581 386 - ------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $(33,666) $(31,377) =============================================================
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NOTES (continued) Gulf Power Company 2002 Annual Report
Components of the postretirement plan's net periodic cost were as follows:
2002 2001 2000 - ----------------------------------------------------------------- Service cost $ 948 $ 983 $ 896 Interest cost 3,991 3,886 3,515 Expected return on plan assets (1,100) (1,037) (901) Transition obligation 356 356 355 Prior service cost 346 299 159 Recognized net (gain)/loss (19) (18) 13 - ----------------------------------------------------------------- Net post-retirement cost $ 4,522 $ 4,469 $4,037 =================================================================
An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 9.25 percent for 2002, 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, 2002 as follows (in thousands):
1 Percent Increase Decrease - --------------------------------------------------------------- Benefit obligation $4,846 $4,293 Service and interest costs $381 $325 ===============================================================
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 2002, 2001, and 2000 were $2.5 million, $2.3 million, and $2.2 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. The Company's business activities are also 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 currently filed against the Company cannot be predicted at this time; however, after consultation with legal counsel, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on the Company's financial statements.
Environmental 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 FDEP for the purpose of ensuring compliance with ozone ambient air quality standards adopted by the EPA. During 2002, 2001, and 2000, the Company recorded ECRC revenues of $10.8 million, $10.0 million, and $9.9 million, respectively.
At December 31, 2002, the Company's liability for the estimated costs of environmental remediation projects for known sites was $14.4 million. These estimated costs are expected to be expended from 2003 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 $13.1 million in deferred assets and deferred liabilities representing the future recoverability of these costs.
Environmental Protection Agency Litigation
In November 1999, the EPA brought a civil action in the U.S. District Court against Alabama Power, Georgia Power, and SCS. The complaint alleges violations
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of the New Source Review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. 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 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.
The EPA concurrently issued to the operating companies a notice of violation related to 10 generating facilities, including the five facilities mentioned previously and the Company's Plants Crist and Scherer. See Note 5 under "Joint Ownership Agreements" related to the Company's ownership interest in Georgia Power's Plant Scherer Unit No. 3. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation, and to add the Company, Mississippi Power, and Savannah Electric as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities had failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. On August 1, 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. The court granted the EPA's motion to add Savannah Electric as a defendant, but denied the motion to add the Company and Mississippi Power based on lack of jurisdiction. As directed by the court, the EPA re-filed its amended complaint limiting claims to those brought against Georgia Power and Savannah Electric. Also, the EPA re-filed its claims against Alabama Power in the U.S. District Court in Alabama. It has not re-filed its claims against the Company, Mississippi Power, or SCS.
The Alabama Power, Georgia Power, and Savannah Electric cases have been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA appeal involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA appeal could have a significant adverse impact on Alabama Power and Georgia Power, both companies have been parties to that case as well. In February 2003, the U.S. District Court in Alabama extended the stay of the EPA litigation proceeding in Alabama until the earlier of May 6, 2003 or a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the related litigation involving TVA. On August 21, 2002, the U.S. District Court in Georgia denied the EPA's motion to reopen the Georgia case. The denial was without prejudice to the EPA to refile the motion at a later date, which the EPA has not done 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. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and 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.
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. If the verdict is not overturned, the plaintiff will also be entitled to recover attorney's fees. The Company intends to seek a new trial; however, if the Company is not successful in obtaining a new trial, it intends to pursue an appeal. 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
In 2002, certain subsidiaries of Southern Company, including the Company, Georgia Power, Mississippi Power, Savannah Electric, and Southern Telecom (collectively, defendants), were named as defendants in numerous lawsuits brought by landowners 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
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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. Defendants believe 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.
Retail Rate Case
In September 2001 the Company filed a request with the FPSC for a base rate increase of approximately $70 million, the majority of which was related to the Plant Smith Unit 3 combined cycle facility which was placed in service in April 2002. In May 2002, the FPSC approved a retail base rate increase of $53.2 million effective June 7, 2002.
Retail Revenue Sharing Plan
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. Customers received two-thirds of any revenue within the sharing range and the Company retained one-third. The stipulation also included authorization for the Company, at its discretion, to accrue up to an additional $5 million to the property insurance reserve and $1 million to amortize a regulatory asset related to the corporate office. The FPSC approved stipulation became effective in November 1999.
The Company recorded revenues subject to refund (with interest) of $1.5 million in 2001 and $7.2 million in 2000. No refund was required in 2002.
In addition to the refund, the Company amortized $1.0 million of the regulatory asset related to the corporate office and accrued an additional $1.0 million to the property insurance reserve in 2001. The sharing plan expired April 21, 2002.
4. COMMITMENTS
Construction Program
The Company is engaged in a continuous construction program, the cost of which is currently estimated to total $108 million in 2003, $150 million in 2004, and $156 million in 2005. 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; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2002 significant purchase commitments were outstanding in connection with the construction program.
Included in the amounts above, the Company has budgeted $34 million, $52 million, and $47 million in 2003, 2004, and 2005, 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. The Company's remaining construction program is related to maintaining and upgrading the transmission, distribution, and generating facilities.
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 $96.5 million over approximately 13
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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 prepayment in the Balance Sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed.
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the Company has entered into contract commitments for the procurement of fuel. In some cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Total estimated obligations at December 31, 2002 were as follows:
Year Fuel ---- ---------------- (in millions) 2003 $113 2004 90 2005 92 2006 93 2007 95 2008 and thereafter 312 ---------------------------------------------------------- Total commitments $795 ==========================================================
In addition, SCS acts as an agent for the five operating companies, Southern Power, and Southern GAS with regard to natural gas purchases. Natural gas purchases (in dollars) are based on various indices at the actual time of delivery; therefore, only the volume commitments are firm. The Company's committed volumes are allocated based on usage projections as of December 31 as follows:
Year Natural Gas ----- ---------------- (MMBtu) 2003 24,879,611 2004 15,595,381 2005 5,758,513 2006 3,696,035 2007 1,235,291 -------------------------------------------------------- Total commitments 51,164,831 ========================================================
Additional commitments for fuel will be required to supply the Company's future needs.
Acting as an agent for all of Southern Company's operating companies, Southern Power and Southern GAS, SCS may enter into various types of wholesale energy and natural gas contracts. Each of the operating companies, Southern Power, and Southern GAS may be jointly and severally liable under these agreements. The creditworthiness of Southern Power and Southern GAS is currently inferior to the creditworthiness of the operating companies. Southern Company has entered into keep-well agreements with each of the operating companies to insure it will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power or Southern GAS as a contracting party under these agreements.
Lease Agreements
The Company has operating lease agreements with various terms and expiration dates. Total operating lease expenses were $2.1 million, $1.9 million, and $2.4 million for 2002, 2001, and 2000, respectively.
At December 31, 2002, estimated minimum rental commitments for noncancelable operating leases were as follows:
Year Amounts ---- --------------- (in thousands) 2003 $2,141 2004 2,150 2005 2,165 2006 2,042 2007 2,038 2008 and thereafter 10,190 ------------------------------------------------------------ Total commitments $20,726 ============================================================
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 was entered into for twenty-two years. Both of these leases are for the transportation of coal to Plant Daniel. At the end of each lease term, 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.
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The Company, as a joint owner of Plant Daniel, 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 2002 and $1.9 million in 2001. The annual amounts for 2003 through 2007 are expected to be $1.9 million, $1.9 million, $2.0 million, $2.0 million, and $2.0 million, respectively, and after 2007 are expected to total $10.2 million.
Guarantees
Prior to 1999, a subsidiary of Southern Company originated loans to residential customers of the operating companies 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 its customers' delinquent loans. As of December 31, 2002, the outstanding loans guaranteed by the Company totaled $1 million and a loan loss reserve of $0.2 million has been recorded.
5. 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 MWs. 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.
At December 31, 2002, 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 $187,768(1) $232,272 Accumulated Depreciation $77,476 $119,655 Construction Work in Progress $258 $3,512
Ownership 25% 50% - ------------------------------------------------------------------
(1) Includes net plant acquisition adjustment.
6. LONG-TERM POWER SALES AGREEMENTS
The Company and the other operating affiliates have long-term contractual agreements for the sale of capacity to certain non-affiliated utilities located outside the system's service area. The unit power sales agreements are fixed and pertain to capacity related to specific generating units. Because the energy is generally sold at cost under these agreements, profitability is primarily affected by revenues from capacity sales. The capacity revenues from these sales were $19.9 million in 2002, $19.5 million in 2001, and $20.3 million in 2000.
Unit power from specific generating plants of Southern Company is currently being sold to Florida Power Corporation (FPC), Florida Power & Light Company (FP&L), and Jacksonville Electric Authority (JEA). Under these agreements, 210 megawatts of net dependable capacity were sold by the Company during 2002. Sales will remain close to that level, unless reduced by FP&L, FPC, and JEA with a minimum of three years notice, until the expiration of the contracts in 2010.
7. INCOME TAXES
At December 31, 2002, the tax-related regulatory assets to be recovered from customers were $ 18.8 million. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized allowance for funds used during construction. At December 31, 2002, the tax-related regulatory liabilities to be credited to customers were $29.7
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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 the federal and state income tax provisions are as follows:
2002 2001 2000 ------------------------------------ (in thousands) Total provision for income taxes: Federal-- Current $24,474 $24,207 $37,250 Deferred 7,936 2,568 (11,159) - -------------------------------------------------------------------- 32,410 26,775 26,091 - -------------------------------------------------------------------- State-- Current 3,051 3,701 5,796 Deferred 1,683 826 (1,357) - -------------------------------------------------------------------- 4,734 4,527 4,439 - -------------------------------------------------------------------- Total $37,144 $31,302 $30,530 ====================================================================
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:
2002 2001 --------------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $188,879 $179,071 Other 28,377 27,328 - --------------------------------------------------------------------- Total 217,256 206,399 - --------------------------------------------------------------------- Deferred tax assets: Federal effect of state deferred taxes 9,421 9,009 Postretirement benefits 10,826 9,379 Other 18,396 17,881 - --------------------------------------------------------------------- Total 38,643 36,269 - --------------------------------------------------------------------- Net deferred tax liabilities 178,613 170,130 Less current portion, net (10,924) (8,162) - --------------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $167,689 $161,968 =====================================================================
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 2002, $1.7 million in 2001, and 1.9 million in 2000. At December 31, 2002, 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:
2002 2001 2000 ---------------------------- Federal statutory rate 35% 35% 35% State income tax, net of federal deduction 3 4 4 Non-deductible book depreciation 1 1 1 Difference in prior years' deferred and current tax rate (2) (2) (2) Other, net (1) (3) (1) - ---------------------------------------------------------------- Effective income tax rate 36% 35% 37% ================================================================
The Company and the other subsidiaries of Southern Company file a consolidated federal 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.
8. CAPITALIZATION
Preferred Securities
Statutory business trusts formed by the Company, of which the Company owns all the common securities, have issued mandatorily redeemable preferred securities. The following securities are currently outstanding:
Date of Maturity Issue Amount Rate Notes Date --------------------------------------------------- (millions) (millions) Trust I 01/1997 $40 7.625 $41 12/2036 Trust II 01/1998 45 7.000 46 12/2037 Trust III 11/2001 30 7.375 31 09/2041 Trust IV 12/2002 40 5.600* 41 11/2042
* Issued to redeem the 7.625 percent Trust I preferred securities in January 2003 at a five year initial fixed rate of 5.60 percent and, thereafter, at fixed rates determined through remarketings for specific periods of varying length or at floating rates determined by reference to 3-month LIBOR plus 3.49%.
Substantially all of the assets of each trust are junior subordinated notes issued by the Company in the respective approximate principal amounts set forth above.
The Company considers that the mechanisms and obligations relating to the preferred securities, taken together, constitute a full and unconditional guarantee by the Company of the Trusts' payment obligations with respect to the
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preferred securities. The Trusts are subsidiaries of the Company and accordingly are consolidated in the Company's financial statements.
Securities Due Within One Year
At December 31, 2002, 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 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 2002 and 2001. It is anticipated that the 2003 requirement will be satisfied by certifying property additions. Sinking fund requirements and/or maturities through 2007 applicable to long-term debt are as follows: $60.6 million in 2003; $50.6 million in 2004; $0.6 million in 2005; $37.6 million in 2006; and $0.3 million in 2007.
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, 2002, retained earnings of $127 million were restricted against the payment of cash dividends on common stock under the terms of the mortgage indenture.
Bank Credit Arrangements
At December 31, 2002, the Company had $66.3 million of lines of credit with banks subject to renewal the following year, all of which remained unused. The $66.3 million in committed lines of credit provide liquidity support for Gulf's commercial paper program and for $3.9 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.
Certain credit arrangements contain covenants that limit the level of indebtedness to capitalization to 65 percent. 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, 2002 was $8.5 million.
In addition, the Company has bid-loan facilities with five major money center banks that total $50 million, with none committed at December 31, 2002.
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.
9. QUARTERLY FINANCIAL DATA (Unaudited)
Summarized quarterly financial data for 2002 and 2001 are as follows:
Net Income Operating Operating After Dividends Quarter Ended Revenues Income on Preferred Stock - ---------------------------------------------------------------------- (in thousands) 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
March 2001 $165,029 $24,785 $10,196 June 2001 180,430 30,702 14,770 September 2001 226,616 45,504 26,657 December 2001 153,128 16,268 6,684 - ----------------------------------------------------------------------
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 2002 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 system of internal accounting controls is 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 five 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/Michael D. Garrett Michael D. Garrett President and Chief Executive Officer
/s/Michael W. Southern Michael W. Southern Vice President, Treasurer and Chief Financial Officer
February 17, 2003
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INDEPENDENT AUDITOR'S REPORT
Mississippi Power Company:
We have audited the accompanying balance sheet and statement of capitalization of Mississippi Power Company (a wholly owned subsidiary of Southern Company) as of December 31, 2002, and the related statements of income, comprehensive income, common stockholder's equity, and cash flows for the year 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 audit. The financial statements of Mississippi Power Company as of December 31, 2001, and for each of the two years then ended 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 audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the 2002 financial statements (pages II-189 to II-209) present fairly, in all material respects, the financial position of Mississippi Power Company at December 31, 2002, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.
/s/Deloitte & Touche LLP
Atlanta, Georgia February 17, 2003
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 2002 Annual Report
RESULTS OF OPERATIONS
Earnings
Mississippi Power Company's net income after dividends on preferred stock of $73.0 million in 2002 and $63.9 million in 2001 increased $9.1 million and $8.9 million, respectively, from the prior year. The 2002 increase in net income 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 for 2001 was due primarily to the commercial operation of Plant Daniel Units 3 and 4 and lower interest costs. The Company's 2000 net income after dividends on preferred stock of $55 million was relatively unchanged from the prior year.
A condensed income statement for 2002 including the change by year is as follows:
Increase (Decrease) Amount From Prior Year - ------------------------------------------------------------------ 2002 2002 2001 2000 - ------------------------------------------------------------------- (in thousands) Operating revenues $824,165 $ 28,100 $ 108,463 $54,598 - ------------------------------------------------------------------- Fuel 282,393 4,447 86,819 18,441 Purchased power 51,333 (43,911) (11,895) 36,052 Other operation and maintenance 232,013 41,015 23,193 (4,571) Depreciation and amortization 57,638 3,561 3,802 1,069 Taxes other than income taxes 55,518 10,552 (3,720) 793 - ------------------------------------------------------------------- Total operating expenses 678,895 15,664 98,199 51,784 - ------------------------------------------------------------------- Operating income 145,270 12,436 10,264 2,814 Other income (expense), net (26,378) 2,036 4,828 (2,412) Less -- Income taxes (45,879) (5,346) (6,177) (239) - ------------------------------------------------------------------- Net Income $ 73,013 $ 9,126 $ 8,915 $ 163 ===================================================================
Revenues
Details of the Company's operating revenues in 2002 and the prior two years are as follows:
Amount -------------------------------------- 2002 2001 2000 -------------------------------------- (in thousands) Retail - prior year $489,153 $498,551 $469,434 Change in -- Base rates 38,143 - - Sales growth 566 (1,048) (11,510) Weather 3,533 (1,953) 7,167 Fuel cost recovery and other 5,432 (6,397) 33,460 - ----------------------------------------------------------------- Total retail 536,827 489,153 498,551 - ----------------------------------------------------------------- Sales for resale -- Non-affiliates 224,275 204,623 145,931 Affiliates 46,314 85,652 27,915 - ----------------------------------------------------------------- Total sales for resale 270,589 290,275 173,846 - ----------------------------------------------------------------- Other electric operating revenues 16,749 16,637 15,205 - ----------------------------------------------------------------- Total electric operating revenues $824,165 $796,065 $687,602 ================================================================= Percent change 3.5% 15.8% 8.6% - -----------------------------------------------------------------
Total 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. Retail revenues for 2000 reflected a 6.2 percent increase over the prior year due to increased fuel revenues and a positive weather impact.
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.
Sales for resale to non-affiliates are influenced by the non-affiliate utilities' own customer demand, plant availability, and the cost of their predominant fuels. Included in sales for resale to non-affiliates are revenues from rural electric cooperative associations and municipalities located in
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southeastern Mississippi. Energy sales to these utilities increased 8.0 percent in 2002, decreased 3.7 percent in 2001 and increased 10.9 percent in 2000, with the related revenues increasing 19.8 percent, decreasing 2.4 percent and increasing 10.8 percent, respectively. The customer demand experienced by these utilities is determined by factors very similar to those of the Company. Revenues from sales for resale to non-affiliates increased in 2002 and 2001, primarily as the result of a new power sales contract associated with Plant Daniel Units 3 and 4 that began in June 2001 as well as colder winter months during 2002. Revenues from sales for resale to non-affiliates increased in 2000 as a result of off system sale transactions that were generally offset by corresponding purchase transactions. These transactions had no significant impact on net income.
Energy sales to affiliated companies within the Southern Company electric system, as well as purchases, will 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.
Kilowatt-hour (KWH) sales for 2002 and percent change by year were as follows:
KWH Percent Change 2002 2002 2001 2000 ------------------------------------------------------------------ (in millions) Residential 2,300 6.3% (5.4)% 1.7% Commercial 2,902 2.1 (1.5) 1.3 Industrial 4,162 (2.7) (2.3) (0.7) Other 40 - (0.3) 2.5 -------- Total retail 9,404 0.1 (2.8) 0.5 Sales for Resale Non-Affiliated 5,380 7.4 36.4 12.9 Affiliated 1,587 (46.3) 552.3 (16.2) -------- Total 16,371 (5.3) 26.0 2.8 ==================================================================
Total retail kilowatt-hour sales increased slightly in 2002 due to colder than average winter weather, which primarily affects residential sales. In addition, commercial sales increased 2.1 percent 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. Total retail kilowatt-hour sales increased slightly in 2000, primarily as a result of weather impacts. 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.
Expenses
Total operating expenses were $679 million in 2002, reflecting an increase of 2.4 percent over the prior year. The increase was due primarily to the increase in fuel expense, the increase 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. 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 8 to the financial statements under "Lease Agreements" for additional information. In 2000, total operating expenses increased by 10.1 percent over the prior year due primarily to higher fuel and purchased power expenses.
Fuel costs are the single largest expense for the Company. Fuel expenses for 2002, 2001 and 2000 increased 1.6 percent, 45.4 percent and 10.7 percent, respectively. The increase for 2002 was due to a fuel hedging loss, which is approved for recovery by the Mississippi Public Service Commission (MPSC) through the energy cost management plan (ECM). The 2001 increase was due to increased generation including Plant Daniel Units 3 and 4 and a higher average cost of fuel. The 2000 increase was due to increased generation and a higher average cost of fuel.
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 expenses 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. In 2000, purchased power expenses increased 51.0 percent primarily due to an increase in off-system purchases used to meet off-system sales commitments. These transactions had no significant effect on earnings.
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The amount and sources of generation and the average cost of fuel per net kilowatt-hour generated were as follows:
2002 2001 2000 - ---------------------------------------------------------------- Total generation (millions of kilowatt hours) 15,079 15,770 11,688 Sources of generation (percent) -- Coal 57 59 83 Gas 43 41 17 Average cost of fuel per net kilowatt-hour generated (cents) -- 2.03 1.89 1.80 - ----------------------------------------------------------------
Other operation expenses increased 17.4 percent in 2002 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. In 2000, other operation expense decreased 8.2 percent primarily due to decreases in expenses related to labor costs, legal costs and services provided by SCS. Maintenance expense in 2002 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. Maintenance expense in 2000 increased 12 percent primarily due to additional scheduled maintenance. Depreciation and amortization expense increased 6.6 percent and 7.6 percent in 2002 and 2001, 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. In 2000, depreciation expense increased 2.2 percent due to growth in plant investment and new depreciation rates, which became effective January 2000.
Taxes other than income taxes increased 23.5 percent in 2002 due to additional property taxes related to the 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. These taxes increased 1.7 percent in 2000 due to higher municipal franchise taxes resulting from higher retail revenues. Interest on long-term debt decreased in 2002 and 2001 as a result of lower interest rates on debt outstanding.
Effects of Inflation
The Company is subject to rate regulation and income tax laws that are based on the recovery of 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 costs 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 continuing 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. A major factor is a stable regulatory environment and the Company's ability to achieve energy sales growth while containing costs. Expenses are subject to constant review and cost control programs. The Company is also maximizing invested capital and minimizing the need for additional capital by refinancing outstanding obligations, managing the size of its fuel stockpile, raising generating plant availability and efficiency, and aggressively controlling its construction budget.
In the near term, future earnings will depend upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, changes in contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, and the rate of economic growth in the Company's service area. The Company anticipates somewhat slower growth in energy sales as the tourism industry stabilizes within its service area. In addition to tourism, the healthcare and retail trade sectors will provide most of the anticipated energy growth for the commercial class of
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customers, while shipbuilding, food products, and the U.S. government will provide much of the basis for anticipated growth in the industrial sector.
The Company currently operates as a vertically integrated utility providing electricity to customers within its traditional service area located in southeastern Mississippi. 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.
In August 2001, the Company filed a request with the MPSC to increase annual retail rate revenues by approximately $46.4 million. In connection with this request, the MPSC suspended the semi-annual evaluations under Performance Evaluation Plan (PEP). In December 2001, the MPSC approved an increase of approximately $39 million, which took effect in January 2002. Additionally, the MPSC ordered the Company to reactivate the semi-annual evaluations under PEP, beginning with the 12-month period ending December 31, 2002. PEP will remain in effect until the MPSC modifies, suspends or terminates the plan. 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 $39 million 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 Rate Adjustment Plans" for additional information.
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 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.
In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash pension income, before taxes, of approximately $2.5 million. Future pension income is dependent on several factors including trust earnings and changes to the plan. Current estimates indicate a reversal of recording pension income to recording pension expense by as early as 2005. Postretirement benefit costs for the Company were $4 million in 2002 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. These costs are components of the Company's regulated rates and do not have a significant effect on net income. For more information, see Note 2 to the financial statements.
The Company has a power sale contract with a subsidiary of Dynegy, Inc. (Dynegy). Dynegy is currently experiencing liquidity problems and its credit rating is now below investment grade. Minimum capacity revenues under this contract average approximately $21 million annually through May 2011. Dynegy has provided a letter of credit expiring in April 2003 totaling $26 million - approximately 15 months of capacity payments - to the Company. The letter of credit can be drawn in the event of a default under the agreement or the failure to renew the letter of credit prior to expiration. In the event of such a default, and if the Company is unable to resell that capacity into the market, future earnings could be affected. The outcome cannot now be determined.
The Company is involved in various matters being litigated. See Note 3 to the financial statements for information regarding material issues that could possibly affect future earnings.
Compliance costs related to current and future environmental laws, regulations, and litigation could affect earnings if such costs are not fully recovered. The Clean Air Act and other important environmental items are discussed later in Financial Condition under "Environmental Matters."
Industry Restructuring
The electric utility industry in the United States is continuing to evolve as a result of regulatory and competitive factors. Among the primary agents of change has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows independent power producers (IPPs) to access a utility's transmission network in order to sell electricity to other utilities. This enhances the incentive for
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IPPs to build power plants for a utility's large industrial and commercial customers where retail access is allowed and sell energy to other utilities. Also, electricity sales for resale rates are affected by numerous potential new energy suppliers, including power marketers and brokers.
In 2002, merchant energy companies and traditional electric utilities with significant energy marketing and trading activities came 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 SCS.
Although the Energy Act does not provide for retail customer access, it was a major catalyst for the current restructuring and consolidation taking place within the utility industry. Numerous federal and state initiatives to promote wholesale and retail competition are in various stages. Among other things, these initiatives allow retail customers in some states to choose their electricity provider. As these initiatives materialize, the structure of the utility industry could radically change. 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 this 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.
Continuing to be a low-cost producer could provide significant opportunities to increase market share and profitability in markets that evolve with changing regulation. Conversely, unless the Company remains a low-cost producer and provides quality service, the Company's energy sales growth could be limited, and this could significantly erode earnings.
FERC Matters
In December 1999, the FERC issued its final ruling on Regional Transmission Organizations (RTOs). The order encourages utilities owning transmission systems to form RTOs on a voluntary basis. Southern Company and its operating companies, including the Company, have submitted a series of status reports informing the FERC of progress toward the development of a Southeastern RTO. In these status reports, Southern Company explained that it is developing a for-profit RTO known as SeTrans with a number of non-jurisdictional cooperative and public power entities. In 2001, Entergy Corporation and Cleco Power joined SeTrans development process. In 2002, the sponsors of SeTrans established a Stakeholder Advisory Committee, which will participate in the development of the RTO, and held public meetings to discuss the SeTrans proposal. On October 10, 2002, the FERC granted Southern Company's and other SeTrans' sponsors petition for a declaratory order regarding the governance structure and the selection process for the Independent System Administrator (ISA) of the SeTrans RTO. The FERC also provided guidance on other issues identified in the petition. The SeTrans sponsors announced the selection of ESB International, Ltd. (ESBI) to be the preferred ISA candidate. Should negotiations with this candidate successfully conclude with final agreement among the parties, the SeTrans sponsors intend to seek any state and federal regulatory or other approvals necessary for formation of the SeTrans RTO and the approval of ESBI to serve in the capacity of the SeTrans ISA. The creation of SeTrans is not expected to have a material impact on the Company's financial statements; however, the outcome of this matter 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
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transmission component of bundled retail service; (5) establish a generation reserve margin; (6) establish bid caps for a day ahead and spot energy markets; and (7) revise the FERC policy on the pricing of transmission expansions. Comments on certain aspects of the proposal have been submitted by Southern Company. Any impact of this proposal on the Company will depend on the form in which final rules may be ultimately adopted; however, the Company's revenues, expenses, assets, and liabilities could be adversely affected by changes in the transmission regulatory structure in its regional power market.
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, yield an overall just and reasonable rate. The hearing is scheduled for September 2003. The Company believes that it is in full compliance with the terms of the contract, which has been in place since 1982, and does not believe that the FERC investigation will have a significant impact on the Company's financial results. However, the outcome of the FERC's investigation cannot be predicted.
Accounting Policies
Critical Policies
The Company's significant accounting policies are described in Note 1 to the financial statements. The Company's most critical accounting policy involves rate regulation. The Company is subject to the provisions of FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of the Company's operation is no longer subject to these provisions, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
Additionally, the Company accounts for its lease agreement with Escatawpa Funding, Limited Partnership (Escatawpa) as an operating lease. Under this agreement, Escatawpa, a special purpose entity, is owner-lessor of the combined-cycle generating units at the Company's Plant Daniel. The Company does not consolidate this entity since parties unrelated to the Company have made substantive residual equity capital investments in excess of 3 percent. Recently, FASB Interpretation No. 46, Consolidation of Variable Interest Entities, was issued. Under Interpretation No. 46, Escatawpa is a variable interest entity, which the Company, as primary beneficiary, would be required to consolidate, including both the leased asset and related debt, as of July 1, 2003. Unless the Escatawpa arrangement is restructured to comply with Interpretation No. 46, the Company would recognize a cumulative effect adjustment of approximately $13 million, net of tax, related to depreciation. The Company's current operating lease arrangement with Escatawpa has been reviewed and approved by the MPSC and is reflected and approved for recovery in both its retail and wholesale rate jurisdictions. Consolidation of the leased asset and related debt or restructuring this arrangement could require the Company to seek additional regulatory review. The Company will continue to analyze the impact of Interpretation No. 46 and its regulatory and restructuring options. See "Financial Condition - Off-Balance Sheet Financing Arrangements" herein and Note 8 to the financial statements under "Lease Agreements" for additional information.
New Accounting Standards
Derivatives - -----------
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. In October 2002, the Emerging Issues Task Force (EITF) of the FASB announced accounting changes related to energy trading contracts in Issue No. 02-03. In October 2002, the Company prospectively adopted the EITF's requirements to reflect the impact of certain energy trading contracts on a net basis. This change had no material impact on the Company's income statement. Another change also required certain energy trading contracts to be accounted for on an accrual basis effective January 2003. This change had no impact on the Company's current accounting treatment.
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
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expense. FASB Statement No. 143, Accounting for Asset Retirement Obligations, establishes 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 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 non-regulated companies 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 "Regulatory Assets and Liabilities" and "Depreciation and Amortization."
Guarantees - ----------
In November 2002, the FASB issued Interpretation No. 45, Accounting and Disclosure Requirements for Guarantees. This interpretation requires disclosure of certain direct and indirect guarantees as reflected in Note 8 to the financial statements under "Lease Agreements." Also, the interpretation requires recognition of a liability at inception for certain new or modified guarantees issued after December 31, 2002. The adoption of Interpretation No. 45 in January 2003 did not have a material impact on the financial statements.
FINANCIAL CONDITION
Overview
The principal change in the Company's financial condition during 2002 was the addition of approximately $67 million to utility plant. See the Statements of Cash Flows for additional information.
Off-Balance Sheet Financing Arrangements
In 1999, the Company signed an Agreement for Lease and a Lease Agreement with Escatawpa. These agreements called for the Company to design and construct, as agent for Escatawpa, a 1,064 megawatt natural gas combined cycle facility at the Company's Plant Victor J. Daniel Facility (the Facility). In May 2001, the Facility was completed, placed into commercial operation and the initial 10-year lease term began. The completion cost was approximately $370 million. The lease provides for a residual value guarantee (approximately 71 percent of the completion cost) by the Company that is due upon termination of the lease in certain circumstances. The lease also includes a purchase and renewal option based on the completion cost of the Facility. The Company is required to amortize approximately 10 percent of the initial completion cost over the initial ten year period. Eighteen months prior to the end of the initial lease, the Company may elect to renew for another 10 years. If the Company elects to renew the lease, 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, the Company may either exercise its purchase option or the Facility can be sold to a third party. The Company expects that the fair market value of the Facility would substantially reduce or eliminate the payment under the residual value guarantee. In 2002 and 2001, the Company recognized approximately $26 million and $18 million, respectively, in lease expense which includes approximately $3.5 million and $2.4 million, respectively, related to the amortization of the initial completion cost.
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, 2002, 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.
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Derivative positions are monitored using techniques that include market valuation and sensitivity analysis.
The weighted average rate on variable long-term debt outstanding at December 31, 2002 was 1.6 percent. Based on the Company's overall variable rate long-term debt exposure at December 31, 2002, a near-term 100 basis point change in interest rates would not materially affect the Company's financial statements. See Note 1 to the financial statements under "Financial Instruments" for additional information. In addition, 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, 2002, 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 - ------------------------------------------------------------- 2002 2001 - ------------------------------------------------------------ (in thousands) Contracts beginning of year $(3,830) $ 112 Contracts realized or settled (1,562) (101) Current period changes 18,256 (3,841) - ------------------------------------------------------------- Contracts end of year $12,864 $(3,830) ============================================================
At December 31, 2002, 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 clauses. 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, 2002 and 2001, these amounts were not material. See Note 1 to the financial statements under "Financial Instruments" for additional information.
Financing Activity
During 2002, 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:
2002 2001 2000 ----------------------------- Composite interest rate on long-term debt 4.10% 4.60% 6.41%
Composite preferred stock dividend rate 6.33% 6.33% 6.33%
Composite interest rate on preferred securities 7.20% 7.75% 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 issuance bonds, originally due in 2007.
Capital Structure
The Company's ratio of common equity to total capitalization, excluding long-term debt due within one year, decreased from 62.1 percent in 2001 to 62.5 percent at December, 31 2002.
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total $237 million ($76 million in 2003, $86 million in 2004, and $75 million in 2005). The major emphasis within the construction program will be on the upgrade of existing facilities. 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 assurances that costs related to capital expenditures will be fully recovered.
Other Capital Requirements
In addition to the funds required for the Company's construction program, approximately $115 million will be required by the end of 2004 for present sinking fund requirements and maturities of long-term debt. The Company plans to continue, when economically feasible, to retire higher cost debt and preferred
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stock and replace these obligations with lower-cost capital if market conditions permit.
The capital requirements, lease obligations, and purchase commitments - discussed in Notes 4 and 8 to the financial statements - are as follows:
2003 2004 2005 - ---------------------------------------------------------------- (in thousands) Bonds - First mortgage $33,350 $ - $ - Pollution control 850 25 25 Senior notes 35,000 80,000 - Lease obligations 28,000 27,800 27,500 Purchase commitments fuel 191,000 74,000 6,000 Other post retirement benefits 330 330 330 - ----------------------------------------------------------------
Sources of Capital
At the beginning of 2003, the Company had not used any of its available credit arrangements. Credit arrangements are as follows:
Expires ---------------------------------- Total Unused 2003 2004 & Beyond - ----------------------------------------------------------------- (in millions) $97.5 $97.5 $97.5 - - -----------------------------------------------------------------
In addition to these arrangements, to meet short-term cash needs and contingencies, the Company had approximately $63 million of cash and cash equivalents as well as significant cash flow from operating activities. See the Statement of Cash Flows and Note 7 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. At December 31, 2002, the Company had no outstanding commercial paper or extendible commercial notes.
At December 31, 2002, the Company's current liabilities exceed current assets because of scheduled maturity of $35 million in senior notes and the redemption in February 2003 of the 7.45% First Mortgage Bonds in the amount of $33.4 million and the 5.80% Pollution Control Bonds in the amount of $850,000.
It is anticipated that the funds required for construction and other purposes, including compliance with environmental regulations, will be derived 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.
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.
Environmental Matters
New Source Review Enforcement Actions
On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil action in the U.S. District Court against Alabama Power Company, Georgia Power Company, and SCS. The complaint alleges violations of the New Source Review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. 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 operating companies a notice of violation related to 10 generating facilities, which includes 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 notice of violation, and to add Gulf Power, Savannah Electric, and the Company as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of
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violation allege that the utilities had failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978.
The U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and granted the system service company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. 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 over those companies. As directed by the court, the EPA re-filed its amended complaint limiting claims to those brought against Georgia Power and Savannah Electric. Also, the EPA re-filed its claims against Alabama Power in the U.S. District Court in Alabama. It has not re-filed against Gulf Power, SCS, or the Company. The Alabama Power, Georgia Power, and Savannah Electric cases have been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA appeal involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA appeal could have a significant adverse impact on Alabama Power and Georgia Power, both companies have been parties to that case as well. In February 2003, the U.S. District Court in Alabama extended the stay of the EPA litigation proceeding in Alabama until the earlier of May 6, 2003 or a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the related litigation involving TVA. On August 21, 2002, the U.S. District Court in Georgia denied the EPA's motion to reopen the Georgia case. The denial was without prejudice to the EPA to refile the motion at a later date, which the EPA has not done 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 of this matter could establish legal precedent that eventually could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows and possibly financial condition unless such costs can be 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, a major portion of which is expected to be recovered through existing ratemaking provisions. 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. Compliance was required in two phases - Phase I, effective in 1995 and Phase II, effective in 2000. Construction expenditures associated with Phase I were $65 million and Phase II cost did not have a material impact on the company.
In September 1998, the EPA issued regional nitrogen oxide reduction rules to the states for implementation. Compliance is required by May, 31, 2004 for most states, including Alabama. The final rules affect 21 states that do not include Mississippi. The EPA is presently evaluating whether or not to bring an additional 15 states, including Mississippi, under this regional nitrogen oxide rule.
The Company's 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 2 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 Plan" for additional information.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2002 Annual Report
In July 1997, the EPA revised the national ambient air quality standards for ozone and fine 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 ozone standard unlawful and remanded it to the EPA for further rulemaking. The EPA is expected to propose implementation rules designed to address the court's concerns in 2003 and issue final implementation rules in 2004. The remaining legal challenges to the new standards, which were pending before the U.S. Court of Appeals, District of Columbia Circuit, have been resolved.
The EPA plans to designate areas as attainment or nonattainment with the new eight-hour ozone standard by April 2004 and with the new fine particulate standard by December 2004. Based on the most recent air monitoring data, it is likely that the three coastal counties of Mississippi would initially be in attainment with the new eight-hour average ozone standard and the fine particulate matter standard. The impact of any new standards will depend on the development and implementation of applicable regulations.
The EPA has also announced plans to issue a proposed Regional Transport Rule for the fine particulate matter standard by the end of 2003 and to finalize the rule in 2005. This rule would likely require year-round sulfur dioxide and nitrogen oxide emission reductions from power plants as early as 2010. It is not possible at this time to determine the effect such a rule would have on the Company.
Further reductions in sulfur dioxide 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 State Implementation Plans 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. 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. Because new BART rules have not been developed, 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 be applying for renewal of certain Title V operating permits beginning in 2003. The Company is in the process of developing CAM plans, which could indicate a need for improved particulate matter controls at affected facilities. Because the plans are still in the early stages of development, the Company cannot determine the extent to which improved controls could be required or the costs associated with any necessary improvements. Actual ongoing monitoring costs are expensed as incurred and are not material for any period presented.
In December 2000, having completed its utility studies for mercury and other hazardous air pollutants (HAPS), the EPA issued a determination that an emission control program for mercury and, perhaps, other HAPS is forthcoming. The program is being developed under the Maximum Achievable Control Technology provisions of the Clean Air Act. The EPA currently plans to issue proposed rules regulating mercury emissions from electric utility boilers by the end of 2003, and those regulations are scheduled to be finalized by the end of 2004. Compliance could be required as early as 2007. Because the rules have not yet been proposed, the costs associated with compliance cannot be determined at this time.
In December 2002, the EPA issued final and proposed revisions to the New Source Review program under the Clean Air Act. In February 2003, several northeastern states petitioned the D.C. Circuit Court for a stay of the final rules. The proposed rules are open to public comment and may be revised before being finalized by the EPA. If fully implemented, these proposed and final regulations could affect the applicability of the New Source Review provisions
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2002 Annual Report
to activities at the Company's facilities. In any event, any final regulations must be adopted by the state of Mississippi in order to apply to the Company's facilities. The effect of these proposed and final rules cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent emissions limitations have been proposed. Three of these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2002, and the Clean Air Planning Act of 2002, proposed to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills also proposed to limit emissions of carbon dioxide. None of these bills were enacted into law in the 107th Congress. Similar bills have been, and are anticipated to be, introduced in 2003. The Bush Administration's Clear Skies Act was recently reintroduced, and President Bush has stated that it will be high priority for the Administration. Other bills already introduced include the Climate Stewardship Act of 2003, which proposes capping greenhouse gas emissions. The cost impacts of such legislation would depend upon the specific requirements enacted.
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 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. Because this initiative is still under development, it is not possible to determine the effect on the Company at this time.
The Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste and release 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 have recognized in the financial statements the costs to clean up 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 is developing new rules aimed at reducing impingement and entrainment of fish and fish larvae at cooling water intake structures that will require numerous biological studies, and perhaps, retrofits to some intake structures at existing power plants. The new rule was proposed in February 2002 and will be finalized by February 2004. The impact of any new standards will depend on the development and implementation of applicable regulations.
Also, under the Clean Water Act, the EPA and Mississippi Department of Environmental Quality (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. It is not possible to determine the effect on the Company at this time.
The EPA and MDEQ are reviewing and evaluating various other matters including limits on pollutant discharges to impaired waters, hazardous waste disposal requirements, and other regulatory matters. The impact of any new standards will depend on the development and implementation of applicable regulations.
Several major pieces of environmental legislation are being 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 and Community Right-to-Know Act; and the Endangered Species Act.
Compliance with possible additional federal or state legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could also significantly affect the Company. The impact of any
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Mississippi Power Company 2002 Annual Report
new legislation, or changes to existing legislation could affect many areas of the Company's operations. However, the full impact of any such changes cannot be determined at this time.
Cautionary Statement Regarding Forward-Looking Information
This Annual Report includes forward-looking statements in addition to historical information. Forward-looking information includes, among other things, statements concerning projected sales growth and scheduled completion of new generation. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "should," "could," "expects," "plans," "anticipates," "believes," "estimates," "predicts," "projects," "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 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 and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations; current and future litigation; the effects, extent and timing of the entry of additional competition in the markets of the Company; the impact of fluctuations in commodity prices, interest rates, and customer demand; state and federal rate regulations; political, legal, and economic conditions and developments in the United States; internal restructuring or other restructuring options that may be pursued; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company; the ability of counterparties of the Company to make payments as and when due; the effects of, and changes in, economic conditions in the areas in which the Company operates, including the current soft economy; the direct or indirect effects on the Company's business resulting from the terrorist incidents on September 11, 2001, or any similar such incidents or responses to such incidents; financial market conditions and the results of financing efforts; the ability of the Company to obtain additional generating capacity at competitive prices; weather and other natural phenomena; and other factors discussed elsewhere herein and in other reports (including Form 10-K) filed from time to time by the Company with the Securities and Exchange Commission.
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NOTES TO FINANCIAL STATEMENTS Mississippi Power Company 2002 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 operating companies, a system service company (SCS), Southern Communications Services (Southern LINC), Southern Company Gas (Southern GAS), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Power Company (Southern Power), Southern Telecom, and other direct and indirect subsidiaries. The 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. Southern Power was established in 2001 to construct, own, and manage Southern Company's competitive generation assets and sell electricity at market-based rates in the wholesale market. Contracts among the operating companies - related to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power - are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission. SCS provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber optic communication services within the Southeast. Southern GAS, which began operations in August 2002, is a competitive retail natural gas marketer serving communities in Georgia. Southern Holdings is an intermediate holding subsidiary for Southern Company's investments in leveraged leases, alternative fuel products, and an energy services business. Southern Nuclear 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 the 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 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 respective 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.
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 $43.6 million, $44.1 million, and $46.2 million during 2002, 2001, and 2000, 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 $6.4 million in 2002. 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 $16.6 million in 2002. See Note 4 for additional information.
The operating companies, (including the Company), Southern Power, and Southern Gas may jointly enter into various types of wholesale energy, natural gas and certain other contracts, either directly or through SCS as an agent.
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NOTES (continued) Mississippi Power Company 2002 Annual Report
Each participating company may be jointly and severally liable for the obligations incurred under these agreements.
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.
Regulatory assets and (liabilities) reflected in the Balance Sheets at December 31 relate to the following:
2002 2001 ------------------------- (in thousands) Deferred income tax charges $ 12,617 $ 13,394 Vacation pay 5,782 5,810 Premium on reacquired debt 7,776 6,719 Fuel hedging asset 14,558 8,366 Other assets 49 674 Property damage reserve (5,077) (4,044) Deferred income tax credits (20,798) (23,626) Fuel-hedging liabilities (14,990) - Other liabilities (2,450) (1,066) - --------------------------------------------------------------- Total $ (2,533) $ 6,227 ===============================================================
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 reflected in rates.
See "Depreciation and Amortization" for information regarding regulatory assets and liabilities created as a result of the January 1, 2003 adoption of FASB Statement No. 143, Accounting for Asset Retirement Obligations.
Revenues and Fuel Costs
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.
Energy revenues are recognized as services are rendered. Capacity revenues from long-term contracts are recognized at the lesser of the levelized basis or the cash collected 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. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts continued to average less than 1/2 percent of revenues.
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 2002, 3.5 percent in 2001, and 3.5 percent in 2000. 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.
In January 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 present value of the ultimate costs for an asset's future retirement must be recorded in the period in which the liability
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is incurred. The cost must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life.
There was no cumulative effect adjustment to net income resulting from the adoption of Statement No. 143. The Company expects to receive an accounting order from the MPSC to defer the transition adjustment; therefore, the Company recorded a related regulatory asset of $596,000 to reflect the regulatory treatment of these costs under Statement No. 71. The initial Statement No. 143 liability the Company recognized was $979,000, of which $59,000 was added to the accumulated depreciation reserve. The amount capitalized to property, plant, and equipment was $442,000.
The Company has retirement obligations related to ash landfill sites, ash ponds, water wells, and underground storage tanks. The Company has also identified retirement obligations related to certain transmission, distribution, and wireless communication facilities. However, a liability for the removal of these transmission, distribution, and wireless communication 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 its income statement 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. It is estimated that this annual difference will be approximately $75,000. Historically, these costs have been recovered in rates and management believes the actual asset removal costs will continue to be recoverable in rates.
Statement No. 143 does not permit non-regulated companies to continue accruing future retirement costs for long-lived assets that they do not have a legal obligation to retire. However, in accordance with the regulatory treatment of these costs, the Company will continue to recognize the removal costs for these other obligations in its depreciation rates. As of January 1, 2003, the amount included in the accumulated depreciation reserve that represents a regulatory liability for these costs was $70 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.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost. 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 estimated cost of funds used during construction, if applicable. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense except for the maintenance of coal cars and a portion of the railway track maintenance, which are charged to fuel stock and recovered through the Company's fuel clause. The cost of replacements of property - 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 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 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 reevaluated when circumstances or events change.
Cash and Cash Equivalents
For purposes of the Statements of Cash Flows, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
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NOTES (continued) Mississippi Power Company 2002 Annual Report
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 equals 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.
Comprehensive Income
Comprehensive income - consisting of net income and changes in additional minimum pension liability, net of income taxes - is presented in the financial statements. 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.
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 are derivatives. However, in many cases, these contracts qualify as normal purchases and sales and are accounted for under the accrual method. Other 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. Contracts that do not qualify for the normal purchase and sale exception and that do not meet the hedge requirements 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 that are used 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 fair value at December 31 were as follows:
Carrying Fair Amount Value ------------------------- (in millions) Long-term debt: At December 31, 2002 $313 $313 At December 31, 2001 $314 $309 Capital trust preferred securities: At December 31, 2002 $ 35 $ 36 At December 31, 2001 $ 35 $ 35 - ------------------------------------------------------------
The fair values for long-term debt and preferred securities 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
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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 $1.8 million in 2002, $2.5 million in 2001 and $3.5 million in 2000. As of December 31, 2002, the accumulated provision amounted to $5.1 million.
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 Company provides certain medical care and life insurance benefits for retired employees. Substantially all these employees may become eligible for such benefits when they retire. The Company funds trusts to the extent deductible under federal income tax regulations or the extent required by regulatory commissions. In late 2000, as well as 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.
Plan assets consist primarily of domestic and international equities, global fixed income securities, real estate, and private equity investments. The measurement date for plan assets and obligations is September 30 for each year.
Pension Plan
Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows:
Projected Benefit Obligations -------------------------- 2002 2001 - --------------------------------------------------------------------- (in thousands) Balance at beginning of year $172,167 $154,411 Service cost 5,259 4,797 Interest cost 12,674 11,817 Benefits paid (8,386) (8,456) Actuarial gain and employee transfers 528 1,268 Amendments 4,200 8,406 Other - (76) - --------------------------------------------------------------------- Balance at end of year $186,442 $172,167 =====================================================================
Plan Assets -------------------------- 2002 2001 - --------------------------------------------------------------------- (in thousands) Balance at beginning of year $211,546 $256,648 Actual return on plan assets (14,089) (37,214) Benefits paid (7,875) (7,850) Employee transfers (743) (38) - --------------------------------------------------------------------- Balance at end of year $188,839 $211,546 =====================================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
2002 2001 - ------------------------------------------------------------------ (in thousands) Funded status $2,396 $ 39,379 Unrecognized transition obligation (2,180) (2,716) Unrecognized prior service cost 16,669 13,656 Unrecognized net gain (9,087) (45,818) - ------------------------------------------------------------------ Prepaid asset, net 7,798 4,501 Portion included in benefit obligations 7,195 6,670 - ------------------------------------------------------------------ Total prepaid assets recognized in the Balance Sheet $14,993 $ 11,171 ==================================================================
In 2002 and 2001, amounts recognized in the Balance Sheet for accumulated other comprehensive income was $2 million and $0 million, respectively. Intangible assets recognized were $2 million in 2002 and $2 million in 2001.
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Components of the pension plans' net periodic cost were as follows:
2002 2001 2000 - --------------------------------------------------------------- (in thousands) Service cost $ 5,259 $ 4,797 $ 4,357
Interest cost 12,674 11,818 10,912 Expected return on plan assets (18,380) (17,328) (15,910) Recognized net gain (2,654) (3,012) (2,577) Net amortization 650 511 76 - --------------------------------------------------------------- Net pension income $ (2,451) $ (3,214) $(3,142) ===============================================================
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 ------------------------- 2002 2001 - -------------------------------------------------------------- (in thousands) Balance at beginning of year $51,523 $44,952 Service cost 959 922 Interest cost 3,781 3,411 Benefits paid (3,320) (2,918) Actuarial gain and employee transfers 8,225 3,256 Amendments - 1,900 - -------------------------------------------------------------- Balance at end of year $61,168 $51,523 ==============================================================
Plan Assets ---------------------- 2002 2001 - -------------------------------------------------------------- (in thousands) Balance at beginning of year $16,269 $17,843 Actual return on plan assets (516) (1,888) Employer contributions 3,645 3,232 Benefits paid (3,320) (2,918) - -------------------------------------------------------------- Balance at end of year $16,078 $16,269 ==============================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows:
2002 2001 - ------------------------------------------------------------------ (in thousands) Funded status $(45,090) $(35,254) Unrecognized transition obligation 3,582 3,928 Unrecognized prior service cost 1,715 1,821 Unrecognized net gain 10,216 (40) Fourth quarter contributions 1,029 1,268 - ------------------------------------------------------------------ Accrued liability recognized in the Balance Sheets $(28,548) $(28,277) ==================================================================
Components of the postretirement plans' net periodic cost were as follows:
2002 2001 2000 - ----------------------------------------------------------------- (in thousands) Service cost $ 959 $ 922 $ 830 Interest cost 3,781 3,411 3,309 Expected return on plan assets (1,514) (1,409) (1,235) Transition obligation 346 346 346 Prior service cost 106 80 - Recognized net loss - (38) - - ----------------------------------------------------------------- Net postretirement cost $ 3,678 $ 3,312 $ 3,250 =================================================================
The weighted average rates assumed in the actuarial calculations for both the pension plans and postretirement benefits plan were:
2002 2001 2000 ----------------------------------------------------------------- Discount 6.50% 7.50% 7.50% Annual salary increase 4.00 5.00 5.00 Long-term return on plan assets 8.50 8.50 8.50 -----------------------------------------------------------------
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An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 8.75 percent for 2002, 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, 2002 as follows:
1 Percent 1 Percent Increase Decrease - ---------------------------------------------------------------- (in thousands) Benefit obligation $4,438 $3,943 Service and interest costs 331 286 - ----------------------------------------------------------------
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 2002, 2001, and 2000 were $2.6 million, $2.5 million, and $2.3 million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General
The Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are also 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 currently filed against the Company cannot be predicted at this time; however, after consultation with legal counsel, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on the Company's financial statements.
Environmental Litigation
On 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 the SCS. The complaint alleges violations of the New Source Review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. 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 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.
The EPA concurrently issued to the operating companies a notice of violation related to 10 generating facilities, which includes 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 notice of violation and to add Gulf Power, Savannah Electric and the Company as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities had failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. The U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction and granted the SCS' motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. 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 over those companies. As directed by the court, the EPA re-filed its amended complaint limiting claims to those brought against Georgia Power and Savannah Electric. Also, the EPA re-filed its claims against Alabama Power in the U.S. District Court in Alabama. It has not re-filed its claims against Gulf Power, SCS, or the Company.
The Alabama Power, Georgia Power, and Savannah Electric cases have been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review
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enforcement action against the Tennessee Valley Authority (TVA). The TVA appeal involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA appeal could have a significant adverse impact on Alabama Power and Georgia Power, both companies have been parties to that appeal as well. In February 2003, the U.S. District Court in Alabama extended the stay of the EPA litigation proceeding in Alabama until the earlier of May 6, 2003 or a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the related litigation involving TVA. On August 21, 2002, the U.S. District Court in Georgia denied the EPA's motion to reopen the Georgia case. The denial was without prejudice to the EPA to refile the motion at a later date, which the EPA has not done 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. 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 unless such costs can be recovered through regulated rates.
Retail Rate Adjustment Plans
The Company's retail base rates are set under Performance Evaluation Plan (PEP), a rate plan originally approved in 1986 and modified in 1994 and 2002. See "2001 Retail Rate Case." PEP was designed with the objective that the plan would reduce the impact of rate changes on the customer and provide incentives for the Company to keep customer prices low. PEP includes a mechanism for rate adjustments based on the Company's ability to maintain low rates for customers and on the Company's performance as measured by three indicators that emphasize price and 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 2 percent of retail revenues per evaluation period.
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 2 percent of retail revenues. However, the ECO Plan also provides for carryover of any amount over the 2 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 2003 ECO Plan in January 2003, which, if approved as filed, will result in a slight increase in customer prices.
2001 Retail Rate Case
In August 2001, the Company filed a request with the MPSC for a retail rate increase of approximately $46.4 million. In connection with the Company's request, the MPSC suspended the semi-annual evaluations under PEP. In December 2001, the MPSC approved an increase of approximately $39 million, which took effect in January 2002. Additionally, the MPSC ordered the Company to reactivate the semi-annual evaluations under PEP, beginning with the 12-month period ending December 31, 2002. PEP will remain in effect until the MPSC modifies, suspends or terminates the plan. 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 $39 million rate increase authorized in December 2001 and are incorporated into the PEP evaluation filing for the period ending December 31, 2002.
In 1998, the Company was granted a Certificate of Public Convenience and Necessity to build approximately 1,064 megawatts of combined cycle generation at the Company's Plant Daniel site. The certificate and ownership rights were transferred to Escatawpa Funding Limited Partnership (Escatawpa), which is
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currently leasing the facility to the Company. See Note 8 under "Lease Agreements" for additional information. In October 2000, the MPSC approved a cost allocation that allocates a pro-rata share of the Plant Daniel Unit 3 and 4 capacity, along with the Company's existing generation, to the retail jurisdiction. The Company's 2001 retail rate case reflected this methodology and the MPSC's December 2001 order on the retail rate case filing approved the Company's cost allocations.
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 an Energy Cost Management Clause and the cost allocation of Plant Daniel Units 3 and 4, similar to the plans approved by the Company's retail jurisdiction.
Right of Way Litigation
In 2002, the Company, along with Georgia Power, Gulf Power, Savannah Electric, and Southern Telecom (collectively, defendants), were named as defendants in numerous lawsuits brought by landowners 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. Defendants believe 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.
Transmission Facilities Agreement
In January 2002, 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, yield an overall just and reasonable rate. The hearing is scheduled for September, 2003. The Company believes that it is in full compliance with the terms of the contract, which has been in place since 1982, and does not believe that it will have a significant impact on the Company's financial results. However, the outcome of FERC's investigation cannot be predicted.
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.
At December 31, 2002, 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% $65,223 $34,441
Daniel Units 1 and 2 1,000 50% $237,912 $114,481 ---------------------------------------------------------------
The Company's proportionate share of plant operating expenses is included in the corresponding operating expenses in the Statements of Income.
5. LONG-TERM SALES AND FACILITY AGREEMENTS
The Company and the other operating affiliates have long-term contractual agreements for the sale of capacity and energy to certain non-affiliated utilities located outside the Southern system's service area. Because the energy is generally sold at cost under these agreements, profitability is primarily affected by revenues from capacity sales. The Company's capacity revenues under these agreements were not material during the periods reported.
The Company has a 10-year power sale agreement with Dynegy that began in June 2001. The minimum capacity revenue that the Company will receive will
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average approximately $21 million per year through May 2011. Capacity revenues for 2002 and 2001 were approximately $20.3 million and $12.3 million, respectively, and were classified as sales for resale in the Statements of Income. As a result of Dynegy's liquidity problems and under the terms of this contract, Dynegy has provided a letter of credit expiring in April 2003 totaling $26 million that can be drawn in the event of a default under the agreement or the failure to renew the letters of credit prior to expiration.
In 1984, the Company and Entergy Corp. entered into a 40-year transmission facilities agreement whereby Entergy began paying a use fee to the Company covering all expenses relative to ownership and operation and maintenance of a 500 kV line, including amortization of its original $57 million cost. For 2002, 2001 and 2000, use fees collected under this agreement, net of related expenses, amounted to approximately $1.6 million, $2.5 million and $2.6 million respectively, and are included within Other Income in the Statements of Income. See Note 3 under "Transmission Facilities Agreement" for additional information.
6. INCOME TAXES
At December 31, 2002, the tax-related regulatory assets and liabilities were $13 million and $21 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 current enacted tax law and to unamortized investment tax credits.
Details of the federal and state income tax provisions are shown below:
2002 2001 2000 ---------------------------------- (in thousands) Total provision for income taxes Federal -- Current $42,603 $43,596 $28,934 Deferred (3,122) (8,661) 622 ---------------------------------------------------------------- 39,481 34,935 29,556 ---------------------------------------------------------------- State -- Current 6,680 6,698 4,670 Deferred (282) (1,057) 130 ---------------------------------------------------------------- 6,398 5,641 4,800 ---------------------------------------------------------------- Total $45,879 $40,576 $34,356 ================================================================
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:
2002 2001 ------------------------------ (in thousands) Deferred tax liabilities: Accelerated depreciation $157,087 $147,147 Basis differences 7,791 8,271 Other 38,005 34,544 -------------------------------------------------------------- Total 202,883 189,962 -------------------------------------------------------------- Deferred tax assets: Other property basis differences 14,501 15,983 Pension and other benefits 9,546 9,474 Property insurance 1,942 1,547 Unbilled fuel 6,048 5,596 Other 42,891 27,269 -------------------------------------------------------------- Total 74,928 59,869 -------------------------------------------------------------- Total deferred tax liabilities, net 127,955 130,093 Portion included in current assets, net 18,675 8,820 -------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $146,630 $138,913 ==============================================================
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 2002, 2001, and 2000. At December 31, 2002, all
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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:
2002 2001 2000 ------------------------------ Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.4 3.4 3.4 Non-deductible book depreciation 0.5 0.5 0.6 Other (1.0) (0.8) (1.5) -------------------------------------------------------------- Effective income tax rate 37.9% 38.1% 37.5% ==============================================================
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 Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability.
7. CAPITALIZATION
Preferred Securities
Statutory trusts formed by the Company, of which the Company owns all the common securities, have issued mandatorily redeemable preferred securities. In March 2002, Mississippi Power Capital Trust II sold $35 million of its 7.20% Trust Originated Preferred Securities due December 30, 2041, which are guaranteed by the Company. The proceeds of this issuance were used to redeem $35 million of Mississippi Power Capital Trust I 7.75% Trust Originated Preferred Securities originally issued in 1997.
The Company considers that the mechanisms and obligations relating to the preferred securities, taken together, constitute a full and unconditional guarantee by the Company of the Trust's payment obligations with respect to the preferred securities.
Trust II is a subsidiary of the Company, and accordingly is consolidated in the Company's financial statements.
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 is as follows:
2002 2001 ------------------ (in thousands) Bond improvement fund requirement $ 634 $ 650 Less: Portion to be satisfied by certifying property additions 634 650 ------------------------------------------------------------- Cash sinking fund requirement - - Current portion of other long-term debt 68,350 80,000 Pollution control bond cash sinking fund requirements 850 20 ------------------------------------------------------------- Total $69,200 $80,020 =============================================================
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 166-2/3 percent of such requirement.
Bank Credit Arrangements
At December 31, 2002, the Company had total committed credit agreements with banks for approximately $97.5 million, all of which was unused. These credit agreements expire in 2003. Some of these agreements allow short-term borrowings to be converted into term loans, payable in 8 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.
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 $97.5 million in unused credit arrangements provides required liquidity support to the Company's borrowings through a commercial paper program. The Company has a $67 million commercial paper program. At December 31,
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2002, the Company had no outstanding commercial paper or extendible commercial notes. The credit arrangements also provide support to the Company's variable daily rate pollution control bonds.
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.
Dividend Restrictions
The Company's first mortgage bond indenture and the corporate charter contain various common stock dividend restrictions. At December 31, 2002, 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.
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, 2002 was $83.5 million.
Senior Notes
In March 2002, the Company issued $80 million of Series D Floating Rate Senior Notes due March 12, 2004. The proceeds of the sale were used to repay $80 million of Series C Floating Rate Senior Notes due March 28, 2002.
8. COMMITMENTS
Construction Program
The Company is engaged in continuous construction programs, primarily related to transmission and distribution facilities and generating plants, the costs of which are currently estimated to total $76 million in 2003, $86 million in 2004, and $75 million in 2005. 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; FERC rules and transmission regulations; increasing costs of labor, equipment and materials; and cost of capital. At December 31, 2002, significant purchase commitments were outstanding in connection with the construction program.
Long-Term Service Agreements
The Company has entered into a Long-Term Service Agreement (LTSA) with General Electric (GE) for the purpose of securing maintenance support for the 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. However, the LTSA contains various cancellation provisions at the option of the Company.
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 an expense based on actual hours of operation. The Company has recognized $11 million and $9.6 million for 2002 and 2001, respectively, which is included in maintenance expense on the Statements of Income. Total remaining payments to GE under this agreement are currently estimated to total $166.5 million over the next 11 years.
Lease Agreements
In 1989, the Company 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 were for the transport of coal to Plant Daniel.
Gulf Power, as joint owner of Plant Daniel Units 1 and 2, is responsible for one half of the lease cost. 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 2002, $1.9 million in 2001, and $2.1 million in 2000. The Company's
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annual lease payments for 2003 through 2007 will average approximately $2.0 million and after 2007, lease payments total in aggregate approximately $10 million.
In 1999, the Company signed an Agreement for Lease and a Lease Agreement with Escatawpa Funding, Limited Partnership (Escatawpa). These agreements called for the Company to design and construct, as agent for Escatawpa, a 1,064 megawatt natural gas combined cycle facility at the Company's Plant Victor J. Daniel Facility (Facility). The Company entered into this transaction during a period when retail access was under review by MPSC. Additionally, 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 Rate Adjustment Plans" for a description of the Company's PEP formula rate plan. The Facility 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.
In May 2001, the Facility was completed, placed into commercial operation and the initial 10-year lease term began. The completion cost was approximately $370 million. The lease provides for a residual value guarantee (approximately 71% of the completion cost) by the Company that is due upon termination of the lease in certain circumstances. The lease also includes a purchase and renewal option. The purchase price is based on the completion cost of the Facility. The Company is required to amortize approximately 10% of the initial completion cost over the initial ten year period. Eighteen months prior to the end of the initial lease, the Company may elect to renew for another 10 years. If the Company elects to renew the lease, the agreement calls for the Company to amortize an additional 17% of the initial completion cost over the renewal period. Upon termination of the lease, at the Company's option, the Company may either exercise its purchase option or the Facility can be sold to a third party. The Company expects that the fair market value of the Facility would substantially reduce or eliminate the payment under the residual value guarantee. In 2002 and 2001, the Company recognized approximately $26 million and $18 million, respectively, in lease expense which includes approximately $3.5 million and $2.4 million, respectively, related to the amortization of the initial completion cost.
The Company does not consolidate Escatawpa on its balance sheet since parties unrelated to the Company and Southern Company have made substantive residual equity investments in excess of 3 percent. In January 2003, the FASB issued its Interpretation No. 46, Consolidation of Certain Special-Purpose Entities. Under this interpretation, the Company would be required to consolidate Escatawpa as of July 1, 2003, and record a cumulative effect adjustment as if the Company had initially recorded that asset on its books. If the Company does not restructure the existing arrangement, the impact of consolidating Escatawpa would result in a cumulative effect adjustment relating to depreciation of approximately $13 million, net of tax, through June 30, 2003 and additional expenses of approximately $10.8 million annually thereafter. Consolidating the asset and related debt or restructuring the current arrangement could require further regulatory review by the MPSC.
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, 2002, are as follows:
Year Lease Payments (in millions) 2003 $26 2004 26 2005 26 2006 25 2007 25 2008 and thereafter 98 - ------------------------------------------------------------- Total commitments $226 =============================================================
Fuel
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 fuel. In most cases, these contracts contain provisions for price escalations, minimum production levels, and other financial commitments. In addition, the Company utilizes financial instruments to eliminate price volatility.
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Total estimated fixed-price obligations at December 31, 2002 are as follows:
Year Fuel (in millions) 2003 $191 2004 74 2005 6 2006 6 2007 6 2008 and thereafter 65 - ----------------------------------------------------------- Total commitments $348 ===========================================================
In addition, SCS acts as agent for the five operating companies, Southern Power and Southern GAS with regard to natural gas purchases. Natural gas purchases (in dollars) are based on various market indices at the actual time of delivery; therefore, only the volume commitments are firm. The Company's committed volumes allocated based on usage projections, as of December 31, 2002 are as follows:
Year Natural Gas (MMBtu) 2003 42,172,935 2004 25,730,963 2005 9,796,080 2006 6,381,115 2007 2,088,762 - ----------------------------------------------------------- Total commitments 86,169,855 ===========================================================
Additional commitments for fuel will be required to supply the Company's future needs.
Acting as an agent for all of Southern Company's operating companies, Southern Power, and Southern GAS, SCS may enter into various types of wholesale energy and natural gas contracts. Each of the operating companies, Southern Power, and Southern GAS may be jointly and severally liable for the obligations under these agreements. Accordingly, the creditworthiness of Southern Power and Southern GAS are currently inferior to the creditworthiness of the operating companies. Southern Company has entered into keep-well agreements with each of the operating companies, including the Company, 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 GAS as a contracting party under these agreements.
9. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for 2002 and 2001 are as follows:
Net Income After Dividends Operating Operating On Preferred Quarter Ended Revenues Income Stock - ------------------------------------------------------------------- (in thousands) 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
March 2001 $171,312 $23,615 $ 9,757 June 2001 203,949 32,640 16,571 September 2001 235,916 53,263 30,379 December 2001 184,888 23,315 7,180 - -------------------------------------------------------------------
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 2002 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 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 system of internal accounting controls is 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 five independent directors, provides a broad overview of management's financial reporting and control functions. Additionally, a 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
February 17, 2003
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INDEPENDENT AUDITORS' REPORT
Savannah Electric and Power Company:
We have audited the accompanying balance sheet and statement of capitalization of Savannah Electric and Power Company (a wholly owned subsidiary of Southern Company) as of December 31, 2002, and the related statements of income, comprehensive income, common stockholder's equity, and cash flows for the year 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 audit. The financial statements of Savannah Electric and Power Company as of December 31, 2001, and for each of the two years then ended 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 audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the 2002 financial statements (pages II-228 to II-245) present fairly, in all material respects, the financial position of Savannah Electric and Power Company at December 31, 2002, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
/s/Deloitte & Touche LLP Atlanta, Georgia February 17, 2003
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.
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 2002 Annual Report
RESULTS OF OPERATIONS - ---------------------
Earnings
Savannah Electric and Power Company's net income for 2002 totaled $22.9 million, representing an increase of $0.8 million or 3.7 percent from the prior year. Earnings were up primarily due to higher retail revenues, somewhat offset by higher operating expenses.
Earnings were $22.1 million in 2001 and $23.0 million in 2000. Compared to prior years, this represented a 3.9 percent decrease in 2001 and no significant change in 2000.
A condensed income statement is as follows:
Increase (Decrease) Amount From Prior Year - ------------------------------------------------------------------ 2002 2002 2001 2000 - ------------------------------------------------------------------ (in thousands) Operating revenues $299,552 $15,700 $(11,866) $44,124 - ------------------------------------------------------------------ Fuel 54,955 4,159 (6,381) 6,647 Purchased power 75,604 2,518 (2,254) 27,544 Other operation and maintenance 81,018 10,525 (1,927) 5,746 Depreciation and amortization 22,704 (3,247) 711 1,399 Taxes other than income taxes 14,457 473 868 426 ----------------------------------------------------------------- Total operating Expenses 248,738 14,428 (8,983) 41,762 - ------------------------------------------------------------------ Operating income 50,814 1,272 (2,883) 2,362 Other income (expense), net (15,501) 247 134 (710) Less -- Income taxes 12,433 702 (1,843) 1,766 - ------------------------------------------------------------------ Net Income $ 22,880 $ 817 $ (906) $ (114) ==================================================================
Revenues
Total operating revenues for 2002 were $299.6 million, reflecting a 5.5 percent increase when compared to 2001. The following table summarizes the factors affecting operating revenues for the past three years: Amount --------------------------------------- 2002 2001 2000 --------------------------------------- (in thousands) Retail - prior year $269,172 $282,622 $242,265 Change in -- Base rates 5,101 - (499) Sales growth 8,729 (1,541) 6,798 Weather 2,397 (427) 2,973 Fuel cost recovery and other 372 (11,482) 31,085 - ------------------------------------------------------------------ Total retail 285,771 269,172 282,622 - ------------------------------------------------------------------ Sales for resale -- Non-affiliates 6,354 8,884 4,748 Affiliates 4,075 3,205 4,974 - ------------------------------------------------------------------ Total sales for resale 10,429 12,089 9,722 - ------------------------------------------------------------------ Other operating revenues 3,352 2,591 3,374 - ------------------------------------------------------------------ Total operating revenues $299,552 $283,852 $295,718 ================================================================== Percent change 5.5% (4.0)% 17.5% - ------------------------------------------------------------------
Retail revenues increased 6.2 percent or $16.6 million in 2002, declined $13.5 million in 2001, and increased $40.4 million in 2000. 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. The order established a new fuel rate to better reflect current fuel costs and to collect the under-recovered balance. The GPSC-approved FCR anticipated a three year recovery of the under-recovered fuel balance. Due to decreasing fuel costs in late 2001 and early 2002, the Company recovered all of this balance by March 2002. In May 2002, the GPSC
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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 utilities outside the service area under long-term contracts may include both capacity and energy components. These transactions do not have a significant impact on earnings since the energy is generally sold at variable cost.
Sales to affiliated companies within the Southern electric system 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.
Energy Sales
Changes in revenues are influenced heavily by the amount of energy sold each year. Kilowatt-hour (KWH) sales for 2002 and the percent change by year were as follows:
KWH Percent Change ----------- -------------------------- 2002 2002 2001 2000 ----------- --------------------------- (in millions) Residential 1,793 8.1% (0.7)% 5.8% Commercial 1,477 6.4 1.4 6.3 Industrial 793 0.7 (1.6) 12.2 Other 140 4.4 (1.4) 2.5 ----------- Total retail 4,203 5.9 (0.2) 7.1 Sales for resale -- Non-affiliates 151 35.7 43.4 50.3 Affiliates 126 43.4 (1.0) 15.1 ----------- Total 4,480 7.5% 0.6% 7.8% ===============================================================
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, 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. In 2000, total retail energy sales were up by 7.1 percent from the prior year, reflecting increased energy sales of 12.2 percent to industrial customers due to the re-opening of an industrial facility under new ownership. Residential and commercial energy sales also increased reflecting weather-related demand and customer growth.
Expenses
Fuel and purchased power costs constitute the single largest expense for the Company. The mix of energy supply is determined primarily by system load, the unit cost of fuel consumed, and the availability of generating units.
The amount and sources of energy supply and the total average cost of energy supply were as follows:
2002 2001 2000 -------------------------- Total energy supply (millions of KWHs) 4,628 4,310 4,286 Sources of energy supply (percent) -- Coal 45 50 52 Oil - 1 2 Gas 4 3 5 Purchased power 51 46 41 Total average cost of energy supply (cents/KWH) 2.82 2.87 3.09 - -----------------------------------------------------------------
Fuel expense increased 8.2 percent due to increased gas usage and a higher cost of coal in 2002. In 2001, fuel expense decreased 11.2 percent due to a decrease in generation and a slightly lower average cost of fuel. In 2000, fuel expense increased 13.2 percent due to an increase in generation and a higher average cost of fuel.
Purchased power expense increased 3.4 percent in 2002 primarily due to an increase in energy demands. Purchased power from non-affiliates decreased 72.5 percent and increased from affiliates 38.6 percent in 2002 due principally to a purchased power agreement between the Company and Southern Power for energy and capacity from Plant Wansley Units 6 and 7 which began operation in June 2002. Purchased power expense decreased 3.0 percent in 2001 primarily due to lower fuel prices. Purchased power expense, in 2000, increased 57.6 percent over the prior year due to higher energy demands and higher energy prices.
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In 2002, other operation and maintenance expenses increased 14.9 percent. Other operation expense was higher reflecting increased distribution and administrative and general costs and costs 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, outside services including legal, accounting and auditing, 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 increased from 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 lower 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. Other operation and maintenance expenses in 2000 increased 8.6 percent over the prior year. Other operation expense was higher reflecting increased employee benefit expenses. Maintenance expense increased from 1999 reflecting higher power delivery and power generation maintenance costs to support improved customer reliability and unit availability, respectively.
Depreciation and amortization decreased 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 rate order. Depreciation and amortization increased over prior years by 2.8 percent in 2001 and 5.9 percent in 2000 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 2002 and 2001 primarily due to lower interest rates. Interest expense increased in 2000 due to higher rates on variable rate debt and an increase in short-term debt.
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 or the partially offsetting gain that arises through financing facilities with fixed-money obligations such as long-term debt and trust 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 future earnings depends on numerous factors, which include maintaining a stable regulatory environment and achieving energy sales growth while containing costs.
Future earnings in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, energy conservation practiced by customers, the elasticity of demand, and the rate of economic growth in the Company's service area.
The Company currently operates as a vertically integrated utility providing electricity to customers within the traditional service area of southeastern Georgia. Prices for electricity provided by the Company to retail customers are set by the GPSC. 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).
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In November 2001, the Company filed a request with the GPSC for a base rate increase of $24.4 million to recover expenses related to a new purchased power agreement and other operation and maintenance expenses. The Company also filed for a fuel cost recovery decrease in March 2002. 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. All customers saw a net rate decrease effective June 2002. In August 2002, the GPSC denied the Company's request for reconsideration of the base rate case decision. In November 2002, the Company filed a request for an accounting order to defer 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. On December 17, 2002, an accounting order was approved by the GPSC, which allows the deferral of these costs until May 2005. 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 will be retained by the Company. In January 2003, the Company began deferring the costs under the terms of the accounting order.
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 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 planned combined-cycle plant at Plant McIntosh to be built and owned by Southern Power. The annual capacity cost is expected to be approximately $15.0 million. In December 2002, the Company received certification of this capacity from the GPSC.
In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash pension costs of approximately $4.4 million pre-tax in 2002. Future pension costs are dependent on several factors including trust earnings and changes to the plan. Postretirement benefit costs for the Company were approximately $2.6 million in 2002 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.
The Company is involved in various matters being litigated. See Note 3 to the financial statements for information regarding material issues that could possibly affect future earnings.
Compliance costs related to current and future environmental laws and regulations could affect earnings if such costs are not fully recovered. The Clean Air Act and other important environmental items are discussed under "Environmental Matters."
Industry Restructuring
The electric utility industry in the United States is continuing to evolve as a result of regulatory and competitive factors. Among the primary agents of change was the Energy Policy Act of 1992 (Energy Act). The Energy Act allows independent power producers (IPPs) to access the Company's transmission network in order to sell electricity to other utilities. This enhanced the incentive for IPPs to build power plants for a utility's large industrial and commercial customers where retail access is allowed and sell energy to other utilities. Also, electricity sales for resale rates were affected by numerous new energy suppliers, including power marketers and brokers.
This past year, merchant energy companies and traditional electric utilities with significant energy marketing and trading activities came 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.
Although the Energy Act does not provide for retail customer access, it was a major catalyst for 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
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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. 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.
FERC Matters
In December 1999, the FERC issued its final rule on Regional Transmission Organizations (RTOs). The order encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Southern Company and its operating companies, including the Company, have submitted a series of status reports informing the FERC of progress toward the development of a Southeastern RTO. In these status reports, Southern Company explained that it is developing a for-profit RTO known as SeTrans with a number of non-jurisdictional cooperative and public power entities. In 2002, Entergy Corporation and Cleco Power joined the SeTrans development process. In 2002, the sponsors of SeTrans established a Stakeholder Advisory Committee, which will participate in the development of the RTO, and held public meetings to discuss the SeTrans proposal. On October 10, 2002, the FERC granted Southern Company's and other SeTrans' sponsors petition for a declaratory order regarding the governance structure and the selection process for the Independent System Administrator (ISA) of the SeTrans RTO. The FERC also provided guidance on other issues identified in the petition. The SeTrans sponsors announced the selection of ESB International, Ltd. (ESBI) to be the preferred ISA candidate. Should negotiations with this candidate successfully conclude with final agreement among the parties, the SeTrans sponsors intend to seek any state and federal regulatory or other approvals necessary for formation of the SeTrans RTO and the approval of ESBI to serve in the capacity of the SeTrans ISA. The creation of SeTrans is not expected to have a material impact on the Company's financial statements; however, the outcome of this matter 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 a day ahead and spot energy markets; and (7) revise the FERC policy on the pricing of transmission expansions. Comments on certain aspects of the proposal have been submitted by Southern Company. Any impact of this proposal on Southern Company and its subsidiaries, including the Company, will depend on the form in which final rules may be ultimately adopted; however, the Company's revenues, expenses, assets, and liabilities could be adversely affected by changes in the transmission regulatory structure in its regional power market.
Accounting Policies
Critical Policy
The Company's significant accounting policies are described in Note 1 to the financial statements. The Company's only critical accounting policy involves rate regulation. The Company is subject to the provisions of FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of the Company's operations is no longer subject to these provisions, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.
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New Accounting Standards
Derivatives - -----------
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. In October 2002, the Emerging Issues Task Force (EITF) of the FASB announced accounting changes related to energy trading contracts in Issue No. 02-03. In October 2002, the Company prospectively adopted the EITF's requirement to reflect the impact of certain energy trading contracts on a net basis. This change had no material impact on the Company's income statement. Another change also required certain energy trading contracts to be accounted for on an accrual basis effective January 2003. This change had no impact on the Company's current accounting treatment.
Asset Retirement Obligations - ----------------------------
Prior to the adoption of FASB Statement No. 143 in 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, establishes 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 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 non-regulated companies to continue accruing future retirement costs for long-lived assets that they do not have a legal obligation to retire. See Note 1 to the financial statements under "Depreciation and Amortization" and "Regulatory Assets and Liabilities" for information regarding the financial statement impacts of adopting this standard effective January 1, 2003.
Guarantees - ----------
In 2002, the FASB issued Interpretation No. 45, Accounting and Disclosure Requirements for Guarantees. This interpretation requires disclosure of certain direct and indirect guarantees. In addition, it requires recognition of a liability at inception for any new or modified guarantees issued after December 31, 2002. The adoption of this new standard had no impact on the Company's financial statements.
FINANCIAL CONDITION - -------------------
Plant Additions
The principal change in the Company's financial condition in 2002 was the addition of $32.5 million to utility plant. The funds needed for gross property additions are currently provided from operating activities and from financing activities. See Statements of Cash Flows for additional information.
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.
Exposure to Market Risks
Due to cost-based 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.
The weighted average rate on variable rate long-term debt outstanding at December 31, 2002 was 2.0 percent. If the Company sustained a 100 basis point change in interest rates for all variable rate long-term debt, the change would have affected annualized interest expense by approximately $0.4 million at December 31, 2002. See Note 1 to the financial statements under "Financial Instruments" for additional information. The Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Savannah Electric and Power Company 2002 Annual Report
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, on June 1, 2001, the Company 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 will be $1.1 million for 2003. The program has operated within the defined hedging position limits set for each year.
The fair value of changes in derivative energy trading contracts and year-end valuations are as follows:
Changes in Fair Value - --------------------------------------------------------------- 2002 2001 - --------------------------------------------------------------- (in thousands) Contracts beginning of year $(1,053) $ 36 Contracts realized or settled 269 (32) New contracts at inception - - Changes in valuation techniques - - Current period changes 1,410 (1,057) - --------------------------------------------------------------- Contracts end of year $ 626 $ (1,053) ===============================================================
Source of Year-End Valuation Prices - ------------------------------------------------------------------ Maturity Total ------------------------ Fair Value Year 1 2-3 Years - ------------------------------------------------------------------ (in thousands) - ----------------------------------------------------------------- Actively quoted $626 $986 $(360) External sources - - - Models and other methods - - - - ----------------------------------------------------------------- Contracts end of year $626 $986 $(360) =================================================================
Unrealized gains and losses from mark to market adjustments on contracts related to the retail fuel hedging program are recorded as regulatory assets and liabilities. Realized gains and losses from this program 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. At December 31, 2002, the fair value of derivative energy contracts was reflected in the financial statements as follows:
Amounts - -------------------------------------------------------------- (in thousands) Regulatory liabilities, net $621 Other comprehensive income 0 Net income 5 - -------------------------------------------------------------- Total fair value $626 ==============================================================
Approximately $40 thousand and $35 thousand of gains were recognized in income in 2002 and 2001, respectively. The Company is exposed to market-price risk in the event of nonperformance by parties 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 Note 1 to the financial statements under "Financial Instruments."
Capital Structure
As of December 31, 2002, the Company's capital structure consisted of 46.4 percent common stockholder's equity, 10.3 percent trust preferred securities, and 43.3 percent long-term debt, excluding amounts due within one year.
Maturities and retirements of long-term debt were $53.6 million in 2002, $50.7 million in 2001, and $0.4 million in 2000.
In September 2002, the Company borrowed $25 million under a $30 million variable rate revolving credit agreement which terminates in 2005. The proceeds were used to repay a portion of the Company's short-term indebtedness. In November 2002, the Company issued $55 million of Series D 5.50% senior notes maturing in 2017. The Company used the proceeds to redeem all of the remaining $23.1 million 7.40% Series First Mortgage Bonds due in 2023, to redeem its $30 million Series A 6 5/8% Senior Retail Intermediate Bonds due in 2015, and for general corporate purposes.
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Subsequent to December 31, 2002, the Company refinanced $13.9 million in pollution control bonds from a daily variable interest rate to an auction rate mode.
The composite interest rates and dividend rates for the years 2000 through 2002 as of year-end were as follows:
2002 2001 2000 ------------------------------- Composite interest rates on long-term debt 5.0% 5.9% 6.6% Trust preferred securities dividend rate 6.9% 6.9% 6.9% - -----------------------------------------------------------------
The composite interest rates on long-term debt decreased from 2000 to 2002 due to lower interest rates on variable rate debt and the refinancing of higher priced fixed rate debt.
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total $136.3 million ($41.5 million in 2003, $50.7 million in 2004, and $44.1 million in 2005). Actual construction costs may vary from this estimate because of factors such as changes in: 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 and upgrading of new and existing transmission and distribution facilities and upgrading of generating plants will be continuing.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $47.5 million will be needed by the end of 2005 for maturities of long-term debt and present sinking fund requirements.
Capital requirements, lease obligations, and purchase commitments -- discussed in Notes 4 and 6 to the financial statements -- are as follows:
2003 2004 2005 - ----------------------------------------------------------------- (in thousands) Notes $20,000 $ - $25,000 Leases - Capital 892 836 774 Operating 858 842 775 Purchase commitments Fuel 28,326 15,594 314 Purchased power 12,917 12,694 23,882 - ----------------------------------------------------------------
Sources of Capital
As shown in the chart below, at December 31, 2002, the Company had $55 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.
Bank arrangements are as follows:
Expires ------------------------ Total Unused 2003 2005 ----------------------------------------------------------- (in thousands) $80,000 $55,000 $40,000 $40,000 -----------------------------------------------------------
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 operating companies. At December 31, 2002, the Company had outstanding $2.9 million of 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, 2002, the amount of variable rate obligations outstanding requiring liquidity support was $25.0 million, which includes the $2.9 million outstanding commercial paper.
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It is anticipated that the funds required for construction and other purposes, including compliance with environmental regulations, will be derived from sources similar to those used in the past including both internal and external funds. The external funding came from the issuance of debt and trust 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. The Company received authority from the GPSC for $115 million of such financings expiring December 31, 2003. Currently, the Company has $16.0 million available under this authority.
Environmental Matters
New Source Review Enforcement 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 the system service company. The complaint alleges violations of the New Source Review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. 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 operating companies a notice of violation related to 10 generating facilities, which includes 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 notice of violation and to add Gulf Power, Mississippi Power, and the Company as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal-burning plants constructed or under construction prior to 1978.
The U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and granted the system service company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. 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 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. Also, the EPA refiled its claims against Alabama Power in the U.S. District Court in Alabama. It has not refiled against Gulf Power, Mississippi Power, or the system service company. The Alabama Power, Georgia Power, and the Company's cases have been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA appeal involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and the Company. Because the outcome of the TVA appeal could have a significant adverse impact on Alabama Power and Georgia Power, both companies have been parties to that case as well. In February 2003, the U.S. District Court in Alabama extended the stay of the EPA litigation proceeding in Alabama until the earlier of May 6, 2003 or a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the related litigation involving TVA. On August 21, 2002, the U.S. District Court in Georgia denied the EPA's motion to reopen the Georgia case. The denial was without prejudice to the EPA to refile the motion at a later date, which the EPA has not done 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 any one of these cases could require
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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, a major portion of which is expected to be recovered through existing ratemaking provisions. 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. Compliance was required in two phases -- Phase I, effective in 1995 and Phase II, effective in 2000. Construction expenditures associated with Phase I compliance totaled approximately $2 million. Phase II compliance had no significant impact on the Company.
To help bring the remaining nonattainment areas into compliance with the one-hour ozone standard, in 1998 the EPA issued regional nitrogen oxide reduction rules. Those rules required 21 states, including Georgia, to reduce and cap nitrogen oxide emissions from power plants and other large industrial sources. However, for Georgia, the EPA must complete a separate rulemaking before the requirements will apply. The EPA proposed a rule for Georgia in 2002 and expects to issue a final rule in 2003. The proposed rule requires compliance by May 1, 2005. The Company's additional construction expenditures for compliance with these new rules are currently estimated at approximately $7 million, most of which 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 ozone standard unlawful and remanded it to the EPA for further rulemaking. The EPA is expected to propose implementation rules designed to address the court's concerns in 2003 and issue final implementation rules in 2004. The remaining legal challenges to the new standards, which were pending before the U.S. Court of Appeals, District of Columbia Circuit, have been resolved.
The EPA plans to designate areas as attainment or nonattainment with the new eight-hour ozone standard by April 2004, 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 the new ozone standard. State implementation plans, including new emission control regulations necessary to bring those areas into attainment, could be required as early as 2007. Those state plans 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.
The EPA currently plans to designate areas as attainment or nonattainment with the new fine particulate matter standard by the end of 2004. Those area designations will be based on air quality data collected during 2001 through 2003. Part or all of the Company's service area may be designated nonattainment under the new particulate matter standard. State implementation plans, including new emission control regulations necessary to bring those areas into attainment, could be required as early as the end of 2007. Those state plans will likely require reductions in sulfur dioxide emissions from power plants. If so, the reductions could be required sometime after 2007. Any additional emission reductions and costs associated with the new fine particulate matter standard cannot be determined at this time.
The EPA has also announced plans to issue a proposed Regional Transport Rule for the fine particulate matter standard by the end of 2003 and to finalize the rule in 2005. This rule would likely require year-round sulfur dioxide and nitrogen oxide emission reductions from power plants as early as 2010. If issued, this rule would likely modify other state implementation plan
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requirements for attainment of the fine particulate matter standard and the eight-hour ozone standard. It is not possible at this time to determine the effect such a rule would have on the Company.
Further reductions in sulfur dioxide 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 states to submit State Implementation Plans in 2007 and 2008 that contain emission reduction strategies for achieving progress toward the visibility improvement goal. In 2002, however, the U.S. Court of Appeals, District of Columbia Circuit, vacated and remanded the BART provisions of the federal Regional Haze rules to the EPA for further rulemaking. Because new BART rules have not been developed and state visibility assessments 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 is in the process of developing CAM plans, which could indicate a need for improved particulate matter controls at affected facilities. Because the plans are still in the early stages of development, the Company cannot determine the extent to which improved controls could be required or the costs associated with any necessary improvements. Actual ongoing monitoring costs are expensed as incurred and are not material for any period presented.
In December 2000, having completed its utility studies for mercury and other hazardous air pollutants (HAPS), the EPA issued a determination that an emission control program for mercury and, perhaps, other HAPS is warranted. The program is being developed under the Maximum Achievable Control Technology provisions of the Clean Air Act. The EPA currently plans to issue proposed rules regulating mercury emissions from electric utility boilers by the end of 2003, and those regulations are scheduled to be finalized by the end of 2004. Compliance could be required as early as 2007. Because the rules have not yet been proposed, the costs associated with compliance cannot be determined at this time.
In December 2002, the EPA issued final and proposed revisions to the New Source Review program under the Clean Air Act. In February 2003, several northeastern states petitioned the D.C. Circuit Court for a stay of the final rules. The proposed rules are open to public comment and may be revised before being finalized by the EPA. If fully implemented, these proposed and final regulations could affect the applicability of the New Source Review provisions to activities at the Company's facilities. In any event, any final regulations must be adopted by Georgia in order to apply to the Company's facilities. The effect of these proposed and final rules cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent emissions limitations have been proposed. Three of these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2002, and the Clean Air Planning Act of 2002 proposed to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills also proposed to limit emissions of carbon dioxide. None of these bills were enacted into law in the last Congress. Similar bills have been, and are anticipated to be, introduced this year. The Bush Administration's Clear Skies Act was recently reintroduced, and President Bush has stated that it will be a high priority for the Administration. Other bills already introduced include the Climate Stewardship Act of 2003, which proposes capping greenhouse gas emissions. The cost impacts of such legislation would depend upon the specific requirements enacted.
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
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legislation and has instead announced a new voluntary climate initiative 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. Because this initiative is still under development, it is not possible to determine the effect on the Company at this time.
The Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous 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. The Company may be liable for a portion 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 is developing new rules aimed at reducing impingement and entrainment of fish and fish larvae at cooling water intake structures that will require numerous biological studies, and perhaps, retrofits to some intake structures at existing power plants. The new rule was proposed in February 2002 and is expected to be finalized by August 2004. The impact of any new standards will depend on the development and implementation of applicable regulations.
Also, 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 the Georgia Environmental Protection Division 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.
The EPA and the Georgia Environmental Protection Division are reviewing and evaluating various other matters including limits on pollutant discharges to impaired waters, hazardous waste disposal requirements, and other regulatory matters. The impact of any new standards 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.
Compliance with possible additional federal or state legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could also significantly affect the Company. The impact of any new legislation, or changes to existing legislation, could affect many areas of the Company's operations. The full impact of any such changes cannot, however, be determined at this time.
Cautionary Statement Regarding Forward-Looking Information
This Annual Report includes forward-looking statements in addition to historical information. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "should," "could," "expects," "plans," "anticipates," "believes," "estimates," "predicts," "projects," "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 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 and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and
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regulations; current and future litigation, including the pending EPA civil actions against the Company; the effects, extent, and timing of the entry of additional competition in the markets of the Company; the impact of fluctuations in commodity prices, interest rates, and customer demand; state and federal rate regulations; political, legal, and economic conditions and developments in the United States; internal restructuring or other restructuring options that may be pursued; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial; the ability of counterparties of the Company to make payments as and when due; the effects of, and changes in, economic conditions in the United States, including the current soft economy; the direct or indirect effects on the Company's business resulting from the terrorist incidents on September 11, 2001, or any similar such incidents or responses to such incidents; financial market conditions and the results of financing efforts; the ability of the Company to obtain additional generating capacity at competitive prices; weather and other natural phenomena; and other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed from time to time by the Company with the Securities and Exchange Commission.
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NOTES TO FINANCIAL STATEMENTS Savannah Electric and Power Company 2002 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 operating companies, Southern Power Company (Southern Power), a system service company, Southern Communications Services (Southern LINC), Southern Company Gas (Southern GAS), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The operating companies provide electric service in four southeastern states. Southern Power was established in 2001 to construct, own, and manage Southern Company's competitive generation assets and sell electricity at market-based rates in the wholesale market. Contracts among the operating companies and Southern Power--related to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power--are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission. The system service company provides, at cost, specialized services to Southern Company and subsidiary companies. Southern LINC provides digital wireless communications services to the operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern GAS, which began operation in August 2002, is a competitive retail natural gas marketer serving communities in Georgia. Southern Holdings is an intermediate holding subsidiary for Southern Company's investments in leveraged leases, alternative fuel products, and an energy services business. Southern Nuclear 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 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 the system service company 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 $15.6 million, $15.0 million, and $15.1 million during 2002, 2001, and 2000, respectively. Cost allocation methodologies used by the system service company 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 costs in 2002 amounted to $23.2 million. At December 31, 2002, approximately $1.5 million in prepaid capacity expense related to this agreement was recorded in other deferred debits in the balance sheet.
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 4 under "Fuel and Purchased Power Commitments" for additional information.
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 $1.8 million in 2002.
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The operating companies, including the Company, Southern Power, and Southern GAS may jointly enter into various types of wholesale energy, natural gas and certain other contracts, either directly or through the system service company as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements.
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 could be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the Balance Sheets at December 31 relate to:
2002 2001 -------------------------- (in thousands) Deferred income tax charges $11,692 $ 12,283 Premium on reacquired debt 8,103 6,890 Deferred McIntosh maintenance costs 5,790 53 Fuel-hedging assets - 1,018 Fuel-hedging liabilities (621) - Deferred income tax credits (12,445) (13,776) Storm damage reserves (5,603) (4,228) Accelerated cost recovery (7,282) (8,000) - --------------------------------------------------------------- Total $ (366) $ (5,760) ===============================================================
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.
See "Depreciation and Amortization" in this Note for information regarding significant regulatory assets and liabilities created as a result of the January 1, 2003 adoption of FASB Statement No. 143, Accounting for Asset Retirement Obligations.
Revenues and Fuel Costs
The Company currently operates as a vertically integrated utility providing electricity to retail customers within its traditional service area of southeastern Georgia and to wholesale customers in the Southeast.
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.
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 2002 and 3.0 percent in both 2001 and 2000. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost--together with the cost of removal, less salvage--is charged to the accumulated provision for 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 accordance with regulatory requirements, prior to the implementation of FASB Statement No. 143 in 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 2002, 2001, and 2000, the Company recorded accelerated depreciation of $1.0 million, $2.5 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 depreciation as a credit to depreciation expense over a three year period beginning June 2002. See Note 3 under "Retail Regulatory Matters" for more information.
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In January 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 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 cost must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life.
The cumulative effect adjustment to net income resulting from the adoption of Statement No. 143 was immaterial. The Company expects to receive an accounting order from the GPSC to defer the transition adjustment; therefore, the Company recorded a related regulatory asset of $2.4 million to reflect the Company's regulatory treatment of these costs under Statement No. 71. The initial Statement No. 143 liability the Company recognized was $3.2 million, of which $0.2 million was added to the accumulated depreciation reserve. The amount capitalized to property, plant, and equipment was $1.0 million.
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, a liability for the removal of these transmission and distribution 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 its 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. It is estimated that this annual difference will be approximately $0.2 million. Management believes that actual asset removal costs will be recoverable in rates over time.
Statement No. 143 does not permit non-regulated companies to continue accruing future retirement costs for long-lived assets they do not have a legal obligation to retire. However, in accordance with the regulatory treatment of these costs, the Company will continue to recognize the removal costs for these other obligations in its depreciation rates. As of January 1, 2003, the amount included in the accumulated depreciation reserve that represents a regulatory liability for these costs was $31.9 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. Federal investment tax credits utilized are deferred and amortized to income over the average lives of the related property.
Allowance for Funds Used During Construction (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 2.82 percent in 2002, 5.13 percent in 2001, and 6.87 percent in 2000. AFUDC as a percent of net income was 0.4 percent in 2002, 0.8 percent in 2001, and 0.9 percent in 2000.
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 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 capitalized. 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
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cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a 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 reevaluated 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 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 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.
Comprehensive Income
Comprehensive income - consisting of net income and changes in additional minimum pension liability, net of income taxes - is presented in the Company's financial statements. 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.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in the prices of certain fuel purchases and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities and are measured at fair value. Substantially all of the Company's bulk energy purchases and sales contracts are derivatives. However, in many cases, these contracts qualify as normal purchases and sales and are accounted for under the accrual method. Other 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. Contracts that do not qualify for the normal purchase and sale exception and that do not meet the hedge requirements are marked to market through current period 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.
On June 1, 2001, the Company implemented a natural gas/oil hedging program which was ordered by the GPSC as part of the fuel cost recovery increase filing. 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 will be $1.1 million for 2003. The program has operated within the defined hedging position limits set for each year.
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The Company's other financial instruments for which the carrying amounts did not equal fair value at December 31 were as follows:
Carrying Fair Amount Value -------------------------- (in millions) Long-term debt: At December 31, 2002 $183 $187 At December 31, 2001 $157 $157 Trust preferred securities: At December 31, 2002 $40 $40 At December 31, 2001 $40 $38
The fair values for long-term debt and trust preferred securities were based on either closing market prices or closing prices of comparable instruments.
2. RETIREMENT BENEFITS
The Company has defined benefit, trusteed, non-contributory pension plans that cover substantially all employees. The Company also provides certain non-qualified benefit plans for a select group of management and highly compensated employees. 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. In late 2000, as well as 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.
Plan assets consist primarily of domestic and international equities, global fixed income securities, real estate, and private equity investments. The measurement date for plan assets and obligations is September 30 for each year.
Pension Plans
Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows:
Projected Benefit Obligations ------------------------- 2002 2001 - ------------------------------------------------------------- (in thousands) Balance at beginning of year $79,550 $71,521 Service cost 2,204 2,074 Interest cost 5,811 5,426 Benefits paid (4,213) (3,986) Actuarial loss and employee transfers 1,793 894 Amendments 117 3,621 - ------------------------------------------------------------- Balance at end of year $85,262 $79,550 =============================================================
Plan Assets ------------------------- 2002 2001 - ------------------------------------------------------------- (in thousands) Balance at beginning of year $50,858 $61,880 Actual return on plan assets (2,720) (8,911) Benefits paid (3,734) (3,570) Employee transfers (312) 1,459 - ------------------------------------------------------------- Balance at end of year $44,092 $50,858 =============================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
2002 2001 - ------------------------------------------------------------- (in thousands) Funded status $(41,170) $(28,692) Unrecognized prior service cost 6,847 7,401 Unrecognized net loss (gain) 21,432 12,336 - ------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $(12,891) $ (8,955) =============================================================
In 2002 and 2001, amounts recognized in the balance sheets for accumulated other comprehensive income and intangible assets were $2.0 million and $1.5 million and $0 and $1.6 million, respectively.
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Components of the pension plan's net periodic cost were as follows:
2002 2001 2000 - --------------------------------------------------------------- (in thousands) Service cost $2,204 $2,074 $1,844 Interest cost 5,811 5,426 4,854 Expected return on plan assets (4,311) (4,215) (4,174) Recognized net loss 54 16 - Net amortization 672 700 503 - --------------------------------------------------------------- Net pension cost $4,430 $4,001 $3,027 ===============================================================
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 -------------------------- 2002 2001 - -------------------------------------------------------------- (in thousands) Balance at beginning of year $28,121 $26,124 Service cost 431 433 Interest cost 2,065 2,022 Benefits paid (1,160) (987) Actuarial loss (gain) and employee transfers 3,245 (1,214) Amendments - 1,743 - -------------------------------------------------------------- Balance at end of year $32,702 $28,121 ==============================================================
Plan Assets ------------------------ 2002 2001 - ------------------------------------------------------------ (in thousands) Balance at beginning of year $7,401 $6,910 Actual return on plan assets (732) (789) Employer contributions 2,485 2,267 Benefits paid (1,160) (987) - ------------------------------------------------------------ Balance at end of year $7,994 $7,401 ============================================================
The accrued postretirement costs recognized in the Balance Sheets were as follows:
2002 2001 - ------------------------------------------------------------ (in thousands) Funded status $(24,708) $(20,720) Unrecognized transition obligation 4,938 5,431 Unamortized prior service cost 4,429 4,691 Unrecognized net loss 6,435 1,831 Fourth quarter contributions 2,104 1,577 - ------------------------------------------------------------ Accrued liability recognized in the Balance Sheets $ 6,802) $ (7,190) ============================================================
Components of the postretirement plan's net periodic cost were as follows:
2002 2001 2000 - --------------------------------------------------------------- (in thousands) Service cost $ 431 $ 433 $ 376 Interest cost 2,065 2,022 1,865 Expected return on plan assets (627) (555) (429) Recognized net loss - - 66 Net amortization 756 731 618 - --------------------------------------------------------------- Net postretirement cost $2,625 $2,631 $2,496 ===============================================================
The weighted average rates assumed in the actuarial calculations for both the pension plan and postretirement benefits plan were:
2002 2001 2000 - -------------------------------------------------------------- Discount 6.50% 7.50% 7.50% Annual salary increase 4.00 5.00 5.00 Long-term return on plan assets 8.50 8.50 8.50 - --------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 8.75 percent for 2002, 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, 2002 as follows:
1 Percent 1 Percent Increase Decrease - --------------------------------------------------------------- (in thousands) Benefit obligation $2,138 $1,935 Service and interest costs 168 166 ===============================================================
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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.
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 2002, 2001, and 2000 were $1.0 million, $1.0 million, and $0.9 million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are also 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 currently filed against the Company cannot be predicted at this time; however, after consultation with legal counsel, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on the Company's financial statements.
Environmental Protection Agency Litigation
In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court against Alabama Power, Georgia Power, and the system service company. The complaint alleges violations of the New Source Review provisions of the Clean Air Act with respect to five coal-fired generating facilities in Alabama and Georgia. 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 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.
The EPA concurrently issued to the operating companies a notice of violation related 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 notice of violation, and to add Gulf Power, Mississippi Power, and the Company as defendants. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. These complaints and notices of violation allege that the utilities failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. The U.S. District Court in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and granted the system service company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. 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 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. Also, the EPA refiled its claims against Alabama Power in the U.S. District Court in Alabama. It has not refiled its claims against Gulf Power, Mississippi Power, or the system service company.
The Alabama Power, Georgia Power, and the Company's cases have been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA appeal involves many of the same legal issues raised by the actions against Alabama Power, Georgia Power, and the Company. Because the outcome of the TVA appeal could have
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a significant adverse impact on Alabama Power and Georgia Power, both companies have been parties to that case as well. In February 2003, the U.S. District Court in Alabama extended the stay of the EPA litigation proceeding in Alabama until the earlier of May 6, 2003 or a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the related litigation involving TVA. On August 21, 2002, the U.S. District Court in Georgia denied the EPA's motion to reopen the Georgia case. The denial was without prejudice to the EPA to refile the motion at a later date, which the EPA has not done 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. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and 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 2002, certain subsidiaries of Southern Company, including Georgia Power, Gulf Power, Mississippi Power, the Company, and Southern Telecom (collectively, defendants), were named as defendants in numerous lawsuits brought by landowners 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. Defendants believe 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.
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 rather than the $24.4 million and 13.5 percent return on equity which were requested. 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 August 2002, the GPSC denied the Company's request for reconsideration in this matter and in November 2002, the Company filed a request for an accounting order to defer 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 2002 base rate order. On December 17, 2002, an accounting order was approved by the GPSC, authorizing the Company to defer the $3.8 million in Wansley purchased power costs until May 2005. 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 will be retained by the Company. In January 2003, the Company began deferring the costs under the terms of the accounting order.
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. 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 per year in both 2001 and 2000. As part of the order, the Company was precluded from asking for a rate increase except upon significant changes in economic conditions, new laws, or regulations for the four-year term.
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NOTES (continued) Savannah Electric and Power Company 2002 Annual Report
4. COMMITMENTS
Construction Program
The Company is engaged in a continuous construction program, currently estimated to total $41.5 million in 2003, $50.7 million in 2004, and $44.1 million in 2005. The construction program is subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include: changes in business conditions; acquisition of additional generating assets; revised load growth estimates; changes in environmental regulations; FERC rules and transmission regulations; increasing costs of labor, equipment, and materials; and cost of capital. The Company does not have any traditional baseload generating plants under construction. However, construction related to new and upgrading of existing transmission and distribution facilities and the upgrading of generating plants will continue. At December 31, 2002, significant purchase commitments were outstanding in connection with the construction program.
Fuel and Purchased Power 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. The Company had fuel commitments at December 31, 2002 as follows:
Year Commitments - ---- ---------------- (in thousands) 2003 $28,326 2004 15,594 2005 314 2006 314 2007 314 2008 and thereafter 5,334 - --------------------------------------------------------------- Total commitments $50,196 ===============================================================
In addition, the system service company acts as agent for the Company and the other operating companies and Southern Power with regard to natural gas purchases. Natural gas purchases (in dollars) are based on various indices at the actual time of delivery; therefore, only the volume commitments are firm. The Company's committed volumes allocated based on usage projections as of December 31, 2002 were as follows:
Year Natural Gas - ---- -------------- (MMBtu) 2003 2,140,514 2004 1,282,989 2005 1,158,037 2006 883,956 2007 313,819 2008 and thereafter - - -------------------------------------------------------------- Total commitments 5,779,315 ==============================================================
Additional commitments for fuel will be required to supply the Company's future needs.
Acting as an agent for all of Southern Company's operating companies, Southern Power, and Southern GAS, the system service company may enter into various types of wholesale energy and natural gas contracts. Each of the operating companies, Southern Power, and Southern GAS may be jointly and severally liable under these agreements. The creditworthiness of Southern Power and Southern GAS is currently inferior to the creditworthiness of the operating companies. Accordingly, Southern Company has entered into keep-well agreements with each of the 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 GAS as a contracting party under these agreements.
The Company has entered into two long-term commitments for the purchase of electricity from Southern Power. Estimated total long-term obligations at December 31, 2002 were as follows:
Year Commitments - ---- ---------------- (in thousands) 2003 $12,917 2004 12,694 2005 23,882 2006 26,741 2007 26,722 2008 and thereafter 197,438 - --------------------------------------------------------------- Total commitments $300,394 ===============================================================
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NOTES (continued) Savannah Electric and Power Company 2002 Annual Report
Operating Leases
The Company has rental agreements with various terms and expiration dates. Rental expenses totaled $0.6 million for 2002, $0.4 million for 2001, and $0.4 million for 2000. Of these amounts, $0.5 million in 2002 and $0.4 million in both 2001 and 2000 related to railcar leases and coal dozers and were recoverable through the Company's fuel cost recovery clause.
At December 31, 2002, estimated future minimum lease payments for noncancelable operating leases were as follows:
Year Railcars Other Total - ------------------------------------------------------------- (in thousands) 2003 $ 429 $ 429 $ 858 2004 429 413 842 2005 429 346 775 2006 429 331 760 2007 429 327 756 2008 and thereafter 4,463 528 4,991 - ------------------------------------------------------------- Total minimum payments $6,608 $2,374 $8,982 =============================================================
5. INCOME TAXES
At December 31, 2002, tax-related regulatory assets and liabilities were $11.7 million and $12.4 million, respectively. 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 income tax provisions are as follows:
2002 2001 2000 -------------------------------- (in thousands) Total provision for income taxes Federal -- Currently payable $17,089 $27,991 $11,102 Deferred (5,660) (17,951) 75 - ------------------------------------------------------------------ 11,429 10,040 11,177 - ------------------------------------------------------------------ State -- Currently payable 1,572 4,282 1,744 Deferred (568) (2,577) 653 - ------------------------------------------------------------------ 1,004 1,705 2,397 - ------------------------------------------------------------------ Total $12,433 $11,745 $13,574 ==================================================================
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:
2002 2001 --------------------- (in thousands) Deferred tax liabilities: Accelerated depreciation $83,092 $81,654 Property basis differences (1,250) (1,437) Other 3,630 6,566 - ------------------------------------------------------------------ Total 85,472 86,783 - ------------------------------------------------------------------ Deferred tax assets: Pension and other benefits 12,792 11,403 Other 14,132 10,560 - ------------------------------------------------------------------ Total 26,924 21,963 - ------------------------------------------------------------------ Total deferred tax liabilities, net 58,548 64,820 Portion included in current assets, net 20,422 12,511 - ------------------------------------------------------------------ Accumulated deferred income taxes in the Balance Sheets $78,970 $77,331 ==================================================================
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 2002, 2001, and 2000. At December 31, 2002, 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:
2002 2001 2000 ---------------------------- Federal statutory tax rate 35% 35% 35% State income tax, net of federal income tax benefit 2 3 4 Other (2) (3) (2) --------------------------------------------------------------- Effective income tax rate 35% 35% 37% ===============================================================
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 Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability.
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NOTES (continued) Savannah Electric and Power Company 2002 Annual Report
6. CAPITALIZATION
Trust Preferred Securities
In December 1998, Savannah Electric Capital Trust I, of which the Company owns all of the common securities, issued $40 million of 6.85% mandatorily redeemable preferred securities. Substantially all of the assets of the Trust are $40 million aggregate principal amount of the Company's 6.85% junior subordinated notes due December 31, 2028.
The Company considers that the mechanisms and obligations relating to the trust preferred securities, taken together, constitute a full and unconditional guarantee by the Company of payment obligations with respect to the preferred securities of Savannah Electric Capital Trust I.
Savannah Electric Capital Trust I is a subsidiary of the Company and accordingly is consolidated in the Company's financial statements.
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.
Maturities and retirements of long-term debt were $53.6 million in 2002, $50.7 million in 2001, and $0.4 million in 2000.
In September 2002, the Company borrowed $25 million under a $30 million variable rate revolving credit agreement which terminates September 6, 2005. The proceeds were used to repay a portion of the Company's short-term indebtedness. In November 2002, the Company issued $55 million of Series D 5.50% senior notes maturing November 15, 2017. The Company used these proceeds to redeem all of the remaining $23.1 million 7.40% Series First Mortgage Bonds due July 1, 2023, to redeem its $30 million Series A 6 5/8% Senior Retail Intermediate Bonds due March 17, 2015 and for general corporate purposes.
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.
Securities 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:
2002 2001 ---------------------- (in thousands) Bond sinking fund requirement $ 200 $ 436 Less: Portion to be satisfied by certifying property additions 200 - - -------------------------------------------------------------------- Cash sinking fund requirement - 436 Other long-term debt maturities 20,892 742 - -------------------------------------------------------------------- Total $20,892 $1,178 ====================================================================
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 2001. The 2003 requirement will be satisfied by certifying property additions. Sinking fund requirements and/or maturities through 2007 applicable to long-term debt are as follows: $20.9 million in 2003; $0.8 million in 2004; $25.8 million in 2005; $20.7 million in 2006; and $0.7 million in 2007.
Bank Credit Arrangements
At the end of 2002, credit arrangements with four banks totaled $80 million and expire at various times during 2003 and 2005. In September 2002, the Company borrowed $25 million under a $30 million variable rate revolving credit agreement which terminates in 2005.
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
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NOTES (continued) Savannah Electric and Power Company 2002 Annual Report
percent for the Company. Compensating balances are not legally restricted from withdrawal.
The credit arrangements contain covenants that limit the level of indebtedness to capitalization to 65 percent. Not meeting these limits would result in an event of default under the credit arrangements. In addition, the 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 $5 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 operating companies. At December 31, 2002, the Company had outstanding $2.9 million of commercial paper and no 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, 2002, the amount of variable rate obligations outstanding requiring liquidity support was $25.0 million, which includes the $2.9 million outstanding commercial paper.
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.
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, 2002, approximately $68 million of retained earnings was restricted against the payment of cash dividends on common stock under the terms of the Indenture.
7. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 2002 and 2001 are as follows (in thousands):
Operating Operating Net Quarter Ended Revenues Income Income - -------------------------------------------------------------
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
March 2001 $61,691 $ 6,799 $ 1,476 June 2001 73,970 14,620 6,246 September 2001 93,583 22,332 11,309 December 2001 54,608 5,791 3,032 - -------------------------------------------------------------
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 2002 Annual Report
The management of Southern Power Company has prepared this annual report and is responsible for the financial statements and related information. 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 based upon the recognition that the cost of the system should not exceed its benefits. The Company believes that its system of internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is 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 Southern Company audit committee of its board of directors, composed of five independent directors, provides a broad overview of management's financial reporting and control functions. This committee meets periodically 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 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 Southern Power 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
February 17, 2003
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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, 2002 and 2001, and the related statements of income, comprehensive income, common stockholder's equity, and cash flows for the year ended December 31, 2002 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-260 through II-274) present fairly, in all material respects, the financial position of Southern Power Company at December 31, 2002 and 2001, and the results of its operations and its cash flows for the year ended December 31, 2002 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 February 17, 2003
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Southern Power Company 2002 Annual Report
RESULTS OF OPERATIONS
In January 2001, Southern Power Company was formed as a wholly-owned subsidiary of Southern Company. Southern Power constructs, owns, and manages wholesale generating assets in the Southeast and is the primary growth engine for Southern Company's competitive wholesale energy business.
Earnings
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 Power Purchase Agreements (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 reflect commercial operation of Wansley Units 6 and 7 and Franklin Unit 1 (the New Units) beginning in June 2002 and a full year of Plant Dahlberg operations. As of December 31, 2002, the Company had approximately 2,400 megawatts in commercial operation.
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.
Increase (Decrease) Amount From Prior Year ------------------------------ 2002 2002 - --------------------------------------------------------- (in thousands) Operating revenues $298,768 $269,467 - --------------------------------------------------------- Fuel 97,965 94,186 Purchased power 53,663 48,937 Other operation and maintenance 28,351 21,726 Depreciation and amortization 18,319 15,028 Taxes other than Income taxes 4,275 3,882 - --------------------------------------------------------- Total operating expenses 202,573 183,759 - --------------------------------------------------------- Operating income 96,195 85,708 Other income, net 35,599 32,630 Less -- Interest expense and other, net 49,067 46,329 Income taxes 28,457 25,946 - --------------------------------------------------------- Net Income $54,270 $46,063 =========================================================
Revenues
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 the New Units and the initiation of PPAs with Georgia Power and Savannah Electric and requirements agreements with 11 EMCs in June 2002. A majority of the revenues resulted from wholesale energy sales to affiliated companies under PPAs. The remaining operating revenues are attributed to wholesale energy sales to non-affiliated companies under PPAs and sales through the Southern Company system power pool (Southern Pool).
Capacity revenues for 2002 were $123.9 million, or 41.5% of total revenues. These revenues are an integral component of the PPAs with both associated and non-associated customers.
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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Power Company 2002 Annual Report
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 variable cost.
Expenses
Natural gas fuel costs constitute the single largest expense for the Company. The increase in fuel expense in 2002 is primarily due to the commercial operation of the New Units in 2002 and a full year of operation for Plant Dahlberg. In addition, the average price of natural gas increased 33.4% from 2002 to 2001. The Company's PPAs provide that the purchasers are responsible for substantially all of the cost of fuel relating to energy delivered under such PPAs; therefore, these expense increases do not have a significant impact on net income.
In 2002, purchased power from non-affiliates and affiliates increased by $33.3 million and $15.6 million, respectively, 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, or affiliate-owned generation or external purchases.
In 2001, purchased power from non-affiliates and affiliates totaled $4.7 million. These expenses reflected the demand and the availability and cost of generating resources accessible through the Southern Pool.
In 2002, other operation expense increased by $17.6 million mainly due to increased administrative and general expenses of $12.3 million and other production expenses of $5.2 million. These increases are primarily attributed to the June 2002 commercial operation of the New Units.
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 2002, depreciation and amortization increased as a direct result of the New Units. Depreciation and amortization in 2001 all related to Plant Dahlberg which was placed into service in July 2001.
In 2002, the increase in taxes other than income taxes is related to property taxes for the New Units.
Interest expense in 2002 increased by $40.9 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. The majority of the additional debt is comprised of $575 million in senior notes issued in June 2002 which accounted for $20.0 million of the increased expense. Increased borrowing against the revolving line of credit increased expense by $15.7 million and an increase in the note payable to Southern Company of $209.5 million contributed $5.2 million of the increase. In 2001, interest expense represented interest on long-term debt and interest on borrowings from Southern Company to support the Company's on-going construction program.
These expenses were offset by interest capitalized related to borrowings used to finance the Company's on-going construction program.
Other, net in 2002 decreased primarily due to unrealized losses on derivative energy contracts.
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 2002 and 2001 are not necessarily indicative of future earnings. The level of future earnings depends on numerous factors including completion of construction on new generating facilities, regulatory
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Power Company 2002 Annual Report
matters, energy sales, creditworthiness of customers, total generating capacity available in the Super Southeast, and the remarketing of capacity.
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 6,600 megawatts of available generating capacity in commercial operation. At December 31, 2002, 2,400 megawatts were in commercial operation.
The Company currently has general authorization from the Federal Energy Regulatory Commission (FERC) to sell power to non-affiliates at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. As with any seller that has been authorized to sell at market-based rates, the FERC retains the authority to modify or withdraw the Company's market-based rate authority if it determines that the underlying requirements 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.
In June 2002, PPAs with Georgia Power and Savannah Electric and requirements agreements with 11 EMCs went into effect. Additionally, in June 2002 commercial operation of the New Units began.
In 2003, the Company expects Plant Franklin Unit 2, Plant Harris Units 1 and 2 and Plant Stanton A to be completed and placed into commercial operation. In 2004, the Company's PPA with Georgia Power will begin for Plant Harris Unit 2. The Company also expects Plant Franklin Unit 3 and Plant McIntosh Units 10 and 11 to begin commercial operation in 2005. Substantially all of the Company's generating capacity in operation, under construction or planned has been sold under PPAs. (See Note 5 to the financial statements herein for additional details.)
Also, effective in January 2003, the Company entered into contracts with North Carolina Municipal Power Authority 1 (North Carolina) and the City of Dalton (Dalton). Under the North Carolina contract, the Company will be responsible for supplying North Carolina's capacity and energy needs in excess of its existing resources and disposing of its surplus energy. The contract term is January 1, 2003 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. The contract term is for 15 years, beginning January 1, 2003, with a customer option to convert to a fixed capacity purchase at the end of year 10.
Although under some of the Company's PPAs energy will be sold to Southern Company's five regulated operating companies, the Company's generating facilities will not be in the operating companies' regulated rate bases, and the Company will not be able to seek recovery from the affiliated companies' ratepayers for construction, repair 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 PPA. 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 Standard & Poor's or Moody's downgrades the credit ratings of such counterparty to below-investment grade, or, if the counterparty is not rated or fails to maintain a minimum coverage ratio. The PPAs are expected to provide the Company with a stable source of revenue during their respective terms.
The Company has PPAs with subsidiaries of Dynegy Inc. (Dynegy) which are now rated below investment grade. Minimum capacity revenues under one of these contracts average approximately $13 million annually through May 2005. Dynegy has provided a letter of credit expiring in April 2003 totaling $20 million (approximately 18 months of capacity payments) to the Company. In addition, two one-year letters of credit totaling $50 million (approximately 14 months of capacity payments) were provided in April 2002 as security for obligations of
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Power Company 2002 Annual Report
Dynegy affiliates under the Plant Franklin Unit 3 PPAs beginning in 2005. These letters of credit can be drawn in the event of a default under the PPA or failure to renew the letters of credit prior to expiration. In the event of such a default, and if the Company was unable to resell that capacity in the market, future earnings could be affected. The outcome of this matter cannot now be determined.
In 2002, the Company executed additional PPAs whereby the Company will sell capacity and energy from planned generating facilities at Plant McIntosh to Georgia Power and Savannah Electric beginning in 2005. These PPAs are subject to regulatory approval. Under these contracts and all other existing PPAs, the Company has the right, at its sole discretion, to supply capacity and energy under these arrangements from any resource available to it as part of the Southern Pool. Reference is made to Note 3 to the financial statements herein for additional information.
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 International, Inc. (GE) to reduce its exposure to certain O&M costs relating to GE equipment. See Note 5 to the financial statements herein for additional information.
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 allows independent power producers (IPPs) to access a utility's transmission network in order to sell electricity to other utilities. This enhanced the incentive for IPPs to build power plants for a utility's large industrial and commercial customers where retail access is allowed and sell energy to other utilities. Also, electricity sales for resale rates were affected by numerous new energy suppliers, including power marketers and brokers.
This past year, merchant energy companies and traditional electric utilities with significant energy marketing and trading activities came 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 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.
FERC Matters
In December 1999, the FERC issued its final rule on Regional Transmission Organizations (RTOs). The order encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Southern Company has submitted a series of status reports informing the FERC of progress toward the development of a Southeastern RTO. In these status reports, Southern Company explained that it is developing a for-profit RTO known as SeTrans with a number of non-jurisdictional cooperative and public power entities. In 2001, Entergy Corporation and Cleco Power joined the SeTrans development process. In 2002, the sponsors of SeTrans established a Stakeholder Advisory Committee, which will participate in the development of the RTO, and held public meetings to discuss the SeTrans proposal. On October 10, 2002, the FERC granted Southern Company's and other SeTrans' sponsors petition for a declaratory order regarding the governance structure and the selection process for the Independent System Administrator (ISA) of the SeTrans RTO. The FERC also provided guidance on other issues identified in the petition. The SeTrans sponsors announced the selection of ESB International, Ltd. (ESBI) to be the preferred ISA candidate. Should negotiations with this candidate successfully conclude with final agreement among the parties, the SeTrans sponsors intend to seek any state and federal regulatory or other approvals necessary for formation of the SeTrans RTO and the approval of ESBI to serve in the capacity of the SeTrans ISA. The creation of SeTrans is not expected to have a material impact on the Company's financial statements; however, the outcome of this matter 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)
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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 a day ahead and spot energy markets; and (7) revise the FERC policy on the pricing of transmission expansions. Comments on certain aspects of the proposal have been submitted by Southern Company. Any impact of this proposal on Southern Company and its subsidiaries will depend on the form in which final rules may be ultimately adopted; however, the Company's revenues, expenses, assets, and liabilities could be adversely affected by changes in the transmission regulatory structure in its regional power market.
Environmental Matters
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.
Several major bills to amend the Clean Air Act to impose more stringent emissions limitations have been proposed. Three of these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2002, and the Clean Air Planning Act of 2002, proposed to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills also proposed to limit emissions of carbon dioxide. None of these bills were enacted into law in the last Congress. Similar bills have been, and are anticipated to be, introduced this year. The Bush Administration's Clear Skies Act was recently reintroduced, and President Bush has stated that it will be a high priority for the administration. Other bills already introduced include the Climate Stewardship Act of 2003, which proposes capping greenhouse gas emissions.
Federal and state environmental regulatory agencies are actively considering and developing additional control strategies for emission of air pollution from all major sources of air pollution, particularly electric generating facilities. This includes the overall reduction of emission of nitrogen oxides (NOx) in the eastern United States, the reduction of NOx and particulate matter emissions to reduce regional haze and visibility impairment in sensitive areas, 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 substantial further reductions in all air emissions associated with electricity generation. Additional compliance costs and capital expenditures resulting from the implementation of such rules and standards cannot be determined until the results of legal challenges are known and final rules have been adopted at both the federal and state level.
The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including: control strategies to reduce regional haze; limits on pollutant discharges to impaired waters; cooling water intake restrictions; and hazardous waste disposal requirements. The impact of any new standards will depend on the development and implementation of applicable regulations.
Several major pieces of environmental legislation are being considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation and Recovery Act; the Toxic Substances Control Act; and the Endangered Species Act. Changes to these laws could affect many areas of the Company's operations. The full impact of any such changes cannot be determined at this time.
Compliance with possible additional legislation related to global climate change and other environmental and health concerns could significantly affect the Company. The impact of new legislation, if any, will depend on the subsequent development and implementation of applicable regulations.
All of the Company's PPAs contain provisions that permit charging the purchaser with some of the new costs incurred as a result of change in law, including environmental regulations.
Certain environmental, natural resource and land use concerns could have an effect on site selection for future plants. This includes the potential for designation of target areas as non-attainment for ozone or particulate matter under newly adopted National Ambient Air Quality Standards, the availability of water withdrawal rights, uncertainties regarding aesthetic impacts such as
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increased light or noise or regarding any potential for adverse health impacts associated with electric and magnetic fields. Such concerns and uncertainties can increase the cost of siting and operating any type of electric generating facility.
Accounting Policies
Critical Policies
The Company's significant accounting policies are described in Note 1 to the financial statements. The Company has three critical accounting policies that require a significant amount of judgment and are considered to be the most important to the presentation of the Company's financial position and results of operations. The first critical policy is the recognition of capacity revenues from long-term contracts at the lesser of the levelized basis or the cash collected over the contract periods. Second, the Company designates qualifying derivative instruments as cash flow or fair value hedges under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and marks such derivative instruments to market based primarily on quoted market prices. The unrealized changes in fair value of qualifying cash flow hedges are deferred in other comprehensive income. Any ineffectiveness in those hedges and changes in non-qualifying positions are reported as a component of current period income. Finally, the Company uses flow-through accounting for state manufacturer's tax credits. This means that the Company recognizes the credit as a reduction of tax expense when it is more likely than not to be allowed by the Georgia Department of Revenue.
Derivatives
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. In October 2002, the Emerging Issues Task Force (EITF) of the FASB announced accounting changes related to energy trading contracts in Issue No. 02-03. In October 2002, the Company prospectively adopted the EITF's requirements to reflect the impact of certain energy trading contracts on a net basis. This change had no material impact on the company's income statement. Another change also required certain energy trading contracts to be accounted for on an accrual basis effective January 2003. This change had no impact on the Company's current accounting treatment.
Asset Retirement Obligations
In January 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 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 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 non-regulated companies 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. This represents removal costs accrued prior to the implementation of Statement No. 143.
FINANCIAL CONDITION
Plant Additions
The major change in the Company's financial condition during 2002 was the addition of approximately $1.2 billion to utility plant related to on-going construction of combined-cycle units and the transfer of two units at Plant Wansley from Georgia Power. The funds for these additions were provided by the Company's credit facility, the issuance of senior notes in June 2002, and capital contributions and subordinated loans from Southern Company. The Statements of Cash Flows provide additional information.
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 sales, fixed-price physical gas purchases and agreements covering interest rate swaps and currency swaps. At December 31, 2002, the maximum potential collateral
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Southern Power Company 2002 Annual Report
requirements under the electricity sale contracts and financial instruments were approximately $194 million. Generally, collateral may be provided for by a Southern Company guaranty, a letter of credit or cash. At December 31, 2002, there were no material collateral requirements for the gas purchase contracts.
Exposure to Market Risks
The Company is exposed to market risks, including changes in interest rates, currency exchange rates, and certain 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. The Company's 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, 2002 was 3.65%. If the Company sustained a 100 basis-point change in interest rates for all variable rate long-term debt, the change would affect annualized gross interest cost by approximately $5.6 million at December 31, 2002. Most or all of that change would be capitalized, given the size of the Company's construction program. To further mitigate the Company's exposure to interest rates, it has entered into interest rate swaps that were designated as cash flow hedges for planned debt issuances. 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 7 to the financial statements under the heading "Financial Instruments" for additional information.
The Company has firm purchase commitments that require payment in Euros. As a hedge against fluctuations in the exchange rate for Euros, the Company entered into forward contracts to purchase Euros and has designated these contracts as fair value hedges. Since the terms of these Euro contracts mirror the purchase commitment terms, there is no ineffectiveness recognized in income. At December 31, 2002, the Company had outstanding contracts covering a notional amount of $5.5 million in commitments through May 2003.
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 purchase or sale of fuel and 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 date of the transfers. These contracts were recorded at fair value on the date of the transfer, which was equal to Georgia Power's carrying amount. Following the transfer, these contracts are marked to market through income until realized and settled.
At December 31, 2002 and 2001, the fair value of changes in derivative energy contracts and year-end valuations were as follows:
Changes in Fair Value ------------------------------------------------------------- 2002 2001 ------------------------------------------------------------- (in thousands) Contracts beginning of year $ 5,496 $ -
Contracts realized or settled (4,336) - New contracts at inception 1,576 5,617 Changes in valuation techniques - - Current period changes 1,128 (121) ------------------------------------------------------------ Contracts end of year $ 3,864 $5,496 =============================================================
At December 31, 2002, all of these contracts are actively quoted and mature within one year.
Unrealized 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, 2002, the fair value of derivative energy contracts was as follows:
Amounts - ------------------------------------------------------------ (in thousands) Other comprehensive income $2,706 Net income 1,158 - ------------------------------------------------------------ Total fair value $3,864 ============================================================
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Approximately $(4.9) million and $0.6 million of gains (losses) were recognized in income in 2002 and 2001, respectively. The Company is exposed to market-price risk in the event of nonperformance by parties 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 Note 1 to the financial statements under "Financial Instruments."
Financing Activities
During 2002, Southern Company made to the Company equity contributions of approximately $279.1 million, plus subordinated loans of approximately $209.5 million. Equity contributions and subordinated loans from Southern Company total $941.7 million to the Company at the end of 2002. No dividends were paid in 2002.
In June 2002, the Company issued $575 million of 6.25% Senior Notes, Series A due July 15, 2012. The net proceeds were used to reduce outstanding indebtedness under a revolving credit agreement and to reduce loans from Southern Company. The Company also settled several interest rate swap agreements entered into in anticipation of this issuance at a $16.9 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.
Also in June 2002, the Company issued a long-term note payable to Chilton County, Alabama for $2.1 million. The proceeds of the note were used for the purchase of land for a potential future generation site. The note is payable over the next 5 years at an imputed interest rate of 6.25%.
Capital Requirements for Construction
The Company estimates that construction expenditures for the years 2003 through 2005 will total $377 million, $381 million and $278 million, 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; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital.
The Company has approximately 4,100 megawatts of new generating capacity scheduled to be placed in service by 2005.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $380.6 million will be required by the end of 2005 for maturities of long-term debt.
These capital requirements and purchase commitments -- discussed in Notes 3 and 5 to the financial statements -- are as follows:
2003 2004 2005 - ----------------------------------------------------------------- (in millions) Notes payable to Chilton County $ 0.2 $ 0.2 $ 0.2 Purchase commitments - ----------------------------------------------------------------- Fuel $22.7 $22.9 $18.6 - ----------------------------------------------------------------- Long-term service agreements $17.1 $22.7 $21.4 - -----------------------------------------------------------------
Sources of Capital
The Company will use both external funds and equity capital from Southern Company 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.
At December 31, 2002, the Company had approximately $19.5 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, 2002 approximately $470 million of unused committed credit arrangements with banks as shown in the following table.
At the beginning of 2003, bank arrangements are as follows:
Unused Expiring In -------------------------------- Total Unused 2003 2004 & beyond - ------------------------------------------------------------- (in millions) $850 $470 $-- $470 - -------------------------------------------------------------
Amounts drawn under the arrangements are used to finance acquisition and construction costs related to gas-fired electric generating facilities and for
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general corporate purposes, subject to borrowing limitations for each generating facility. The arrangements permit the Company to fund construction of future generating facilities upon meeting certain requirements. At December 31, 2002, the Company had $380 million in outstanding bank borrowings. See Note 7 to the financial statements under "Long-Term Debt" for additional information.
Cautionary Statement Regarding Forward-Looking Information
The Company's 2002 Annual Report includes forward-looking statements in addition to historical information. Forward-looking information includes, among other things, statements concerning scheduled completion of new generation, capacity projections and the strategic goals for the Company's wholesale business. 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 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 and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations; current and future litigation; the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates; the impact of fluctuations in commodity prices, interest rates, and customer demand; state and federal rate regulations; political, legal, and economic conditions and developments in the United States; the performance of projects undertaken by the Company and the success of efforts to invest in and develop new opportunities; internal restructuring or other restructuring options that may be pursued; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company; the ability of counterparties of the Company to make payments as and when due; the effects of, and changes in, economic conditions in the areas in which the Company operates, including the current soft economy; the direct or indirect effects on the Company's business resulting from the terrorist incidents on September 11, 2001, or any similar such incidents or responses to such incidents; financial market conditions and the results of financing efforts; the ability of the Company to obtain additional generating capacity at competitive prices; weather and other natural phenomena; and other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed from time to time by the Company with the Securities and Exchange Commission.
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NOTES TO FINANCIAL STATEMENTS Southern Power Company 2002 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Southern Power is a wholly owned subsidiary of Southern Company, which is also the parent company of five operating companies, a system service company (SCS), Southern Company Gas (Southern GAS), and other direct and indirect subsidiaries. The 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. 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 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 provides, at cost, specialized services to Southern Company and subsidiary companies. Southern GAS, which began operation in August 2002, is a competitive retail natural gas marketer serving communities in Georgia.
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 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 these estimates.
Southern Power was formed on January 8, 2001. Southern Power began commercial operations in August 2001 after Georgia Power transferred its interest in Plant Dahlberg Units 1 through 10. See Note 2, Asset Transfers, for further information regarding asset transfers from affiliates. The consolidated financial statements include the accounts of Southern Power 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
Southern Power 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 Southern Power. As Southern Power has no employees, all employee related charges are rendered at cost under agreements with SCS or the operating companies. Costs for these services from SCS amounted to approximately $29.5 million and $12 million during 2002 and 2001, respectively, of which approximately $16.2 million in 2002 and $4.7 million in 2001 was 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.
Southern Power has an agreement with Georgia Power to provide operation and maintenance services for Plants Dahlberg, Wansley and Franklin. These services are billed at cost on a monthly basis and are recorded as operations and maintenance expense in the accompanying statements of income. For the periods ended December 31, 2002 and 2001, these services totaled approximately $5.3 million and $1.0 million, respectively.
Additionally, Southern Power 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 2002, Southern Power entered into Power Purchase Agreements (PPAs) with Georgia Power and Savannah Electric for the sale of capacity and energy. Billings under these agreements totaled $165 million, including $13.5
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million of deferred capacity revenues included in deferred capacity revenues on the Balance Sheet at December 31, 2002. See Note 5 herein for additional information.
The operating companies, Southern Power, and Southern 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 5 for information regarding PPAs between Southern Power and Alabama Power, Georgia Power and Savannah Electric.
Southern Power 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 2, 3, 4 and 7 for information related to various types of financing support provided by Southern Company.
Revenues and Fuel Costs
Revenues are recognized as services are rendered. Capacity is sold at rates specified under contractual terms and is recognized at the lesser of the levelized basis or the cash collected over the respective contract periods. Energy is generally sold at market-based rates and the associated revenue is recognized as the energy is delivered.
Significant portions of Southern Power's revenues have been derived from certain customers. For the year ended December 31, 2002, Georgia Power, Savannah Electric, LG&E Energy Marketing, Inc. and Dynegy Power Marketing Inc. accounted for approximately 33.5%, 17.2%, 15.8% and 4.4% 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 3 herein for further details on future commitments.
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. Materials and supplies are recorded at average cost.
Property, Plant and Equipment
Property, plant and equipment are stated at original cost. Original cost includes materials, direct labor incurred by affiliated companies, minor items of property and appropriate administrative costs. Interest is capitalized on qualifying projects during the development and construction period. In 2002 and 2001, interest of approximately $35.3 million and $2.9 million, respectively, 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.
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. 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.
In January 2003, Southern Power 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 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 cost must be capitalized as part of the related long-lived
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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. This represents removal costs accrued prior to the implementation of Statement No. 143.
Impairment of Long-Lived Assets
The Company evaluates long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount 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 to the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a 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 reevaluated 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 at December 31, 2002 and December 31, 2001 were $3.6 million and $4.5 million, respectively.
Financial Instruments
The Company uses derivative financial instruments to hedge exposures to fluctuations in interest rates, foreign currency exchange 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 are derivatives. However, in many cases, these contracts qualify as normal purchases and sales and are accounted for under the accrual method. Other contracts qualify as cash flow hedges of anticipated transactions, resulting in the deferral of related gains and losses, and are recorded in other comprehensive income until the hedged transactions occur. Any ineffectiveness is recognized currently in net income. Contracts that do not qualify for the normal purchase and sale exception and that do not meet the hedge requirements are marked to market through current period income and are recorded on a net basis in the consolidated 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 firm purchase commitments for equipment that require payment in Euros. As a hedge against fluctuations in the exchange rate for Euros, the Company entered into forward contracts to purchase Euros. The Company has designated these contracts as fair value hedges. At December 31, 2002, Southern Power had outstanding contracts covering a notional amount of $5.5 million in commitments through May 2003. The forward contracts to purchase Euros are on the same dates and in the same amounts as the Euro payments that the Company owes for the equipment. As all of the critical terms of the forward Euro purchases (dates and amounts) match those of the Euro payment obligations, the changes in fair value attributable to the risk being hedged are expected to completely offset at inception and on an ongoing basis. Therefore, there is no ineffectiveness related to this hedge.
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Other Southern Power financial instruments for which the carrying amounts did not equal fair value at December 31, 2002 were as follows:
Carrying Fair Amount Value ------------------------ Long-term debt: (in millions) At December 31, 2002 $956 $990 - --------------------------------------------------------------
The fair values for securities were based on either closing market prices or closing prices of comparable instruments.
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.
Comprehensive Income
Comprehensive income -- consisting of net income and changes in the fair value of qualifying cash flow hedges, net of income taxes less reclassifications of amounts included in net income-- is presented in the financial statements. 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.
2. ASSET TRANSFERS
On July 31, 2001, Georgia Power transferred its interests in Plant Dahlberg Units 1 through 10 and related working capital to Southern Power. 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 Southern Power 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 Units 1 & 2 Alabama Power 11/2001 267.9 and Georgia Power Wansley Georgia Power 01/2002 389.9 Units 6 & 7 - -------------------------------------------------------------------
In conjunction with these transfers, Alabama Power and Georgia Power have assigned PPAs related to these plants and certain vendor contracts related to the on-going construction of these facilities to Southern Power. Southern Company has entered into limited keep-well arrangements with Alabama Power and Georgia Power whereby Southern Company will contribute funds to the Company via loans or capital contributions to fund the performance of Southern Power as equipment purchaser under certain arrangements. As of December 31, 2002, Southern Power's remaining purchase obligations to equipment vendors under these contracts totaled $12.2 million.
In addition, Southern Company has entered into keep-well agreements with Alstom Power for the transfer of an equipment contract at the Company's Plant Franklin Unit 3. At December 31, 2002, the amount outstanding under this contract was $0.1 million.
3. CONTINGENCIES AND COMMITMENTS
General Litigation Matters
Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury 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 currently filed against the Company cannot be predicted at this time; however, after consultation with legal
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counsel, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on the Company's financial statements.
Fuel
SCS, as agent for the 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. The total estimated firm costs are as follows:
Fuel Purchases Year (in thousands) - ---- ------------------
2003 $ 22,692 2004 22,890 2005 18,577 2006 18,577 2007 18,577 2008 and beyond 449,588 - ---------------------------------------- Total $550,901 ========================================
Natural gas purchases (in dollars) are based on various indices at the actual time of delivery; therefore, only the volume commitments are firm and disclosed in the following chart.
Total estimated long-term obligations at December 31, 2002 were as follows:
Natural Gas Year MMBtu - ---- ---------------
2003 20,180,312 2004 7,125,668 2005 4,046,104 2006 2,250,859 2007 830,151 2008 and beyond - - ---------------------------------------- Total 34,433,094 ========================================
Purchases of natural gas were approximately $133.5 million and $4.4 million for the periods ended December 31, 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 operating companies, Southern Power and Southern GAS, SCS may enter into various types of wholesale energy and natural gas contracts. Under these agreements, each of the operating companies, Southern Power and Southern GAS may be jointly and severally liable for the obligations of each of the operating companies, Southern Power and Southern GAS. The creditworthiness of Southern Power and Southern GAS is currently inferior to the creditworthiness of the operating companies; therefore, Southern Company has entered into keep-well agreements with each of the 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.
Construction Program
The Company currently estimates property additions to be $377 million, $381 million and $278 million in 2003, 2004 and 2005, respectively. Southern Power has approximately 4,100 megawatts of additional generating capacity scheduled to be placed in service by 2005.
Significant purchase commitments are outstanding in connection with the construction program.
Southern Power's obligations for construction of transmission interconnection facilities to these plants by Alabama Power and Georgia Power totaled $13.5 million and $13 million at December 31, 2002 and 2001, respectively, and are guaranteed by Southern Company.
Southern Company has also granted performance guarantees on behalf of Southern Power and its subsidiary for construction payment obligations associated with Plant Stanton. See Note 4 herein for additional information.
Long-Term Service Agreements
Southern Power has entered into several Long-Term Service Agreements (LTSAs) with General Electric International, Inc. (GE) for the purpose of securing maintenance support for its combined cycle and combustion turbine generating facilities. The LTSAs stipulate that for a fee, GE will perform all planned inspections on the covered equipment, which includes the cost of all labor and
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NOTES (continued) Southern Power Company 2002 Annual Report
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 operation hours of the respective units. Total payments to GE under these agreements are $852 million over the life of the agreements, which are approximately 28 to 30 years per unit. 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 prepayment in the Balance Sheets. Costs are capitalized or charged to expense based on the nature of the work performed.
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 that will total 633 MW upon completion. The unit is co-owned by Orlando Utilities Commission (OUA) (28%), Florida Municipal Power Agency (FMPA) (3.5%), and Kissimmee Utility Authority (KUA) (3.5%). Southern Power has a services agreement with SCS where SCS will be responsible for the operation and maintenance of Stanton A and the overall project management of the construction process. Construction on Stanton A began in October 2001 with an expected completion date of October 1, 2003. At December 31, 2002 and 2001, Southern Power's share of the construction costs for Stanton A was $128.3 million and $31.4 million, respectively, and is recorded in construction work in progress in the consolidated Balance Sheets.
Southern Company has agreed to grant performance guarantees on behalf of Southern Power and its subsidiary, SCF, for SCF's payment obligations under ownership and PPAs associated with the Stanton A project. Southern Power's maximum exposure is $53 million under the construction and ownership agreement and $20 million under the PPAs. See Note 5 herein for additional information.
5. LONG-TERM POWER SALES AGREEMENTS
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 6/04-5/20 --------------------------------------------------- Total Affiliated 4,796 ---------------------------------------------------
Non-Affiliated --------------- Dahlberg Units 1-7 578 6/00-12/04 Dahlberg Units 8-10 225 6/00-5/05 Stanton A 396 11/03-11/13 Franklin Unit 3 625 6/05-5/30 ----------------------------------------------------- Total Non -affiliated 1,824 ----------------------------------------------------- * 370 megawatts during the first year ** 400 megawatts during the first year *** Contract does not begin until second year of operation of Harris Unit 2.
Capacity revenues from these long-term power sales agreements amounted to $120.1 million and $18.6 million for the periods ended December 31, 2002 and 2001, respectively. Future capacity payments to be received under these power sales agreements as of December 31, 2002 are as follows:
Year Payments - ------------------------------------------------------------ Affiliated Non-Affiliated (in millions) 2003 $ 172.5 $ 53.6 2004 241.1 76.2 2005 325.1 127.8 2006 338.2 156.8 2007 336.2 155.4 2008 and beyond 2,040.3 1,319.9 - ------------------------------------------------------------ Total $3,453.4 $1,889.7 - ------------------------------------------------------------
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NOTES (continued) Southern Power Company 2002 Annual Report
Included in the amounts above are capacity payments to be received related to a five-year contract (beginning in 2000) with Dynegy of approximately $13 million annually through May 2005. As a result of Dynegy's liquidity problems, it has provided a letter of credit totaling $20 million which can be drawn in the event of a default under the PPA or the failure to renew the letter of credit prior to expiration in April 2003.
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 Southern Power in connection with the Plant Dahlberg transfer. At December 31, 2002 and 2001, the unamortized balance of these amounts totaled $2.8 million and $4.2 million, respectively, and is being amortized into income over the life of the agreements.
In June 2002, Southern Power began providing services under requirements agreements with 11 Georgia electric municipal cooperatives (EMCs). Under the agreements, Southern Power will coordinate the generating resources and meet the additional capacity requirements of the EMCs. The contracts are in effect through 2009 with options to renew.
Effective in January 2003, the Company entered into contracts with North Carolina Municipal Power Authority 1 (North Carolina) and the City of Dalton (Dalton). Under the North Carolina contract, the Company will be responsible for supplying North Carolina's capacity and energy needs in excess of its existing resources and disposing of its surplus energy. The contract term is for January 1, 2003 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. The contract term is for 15 years, beginning January 1, 2003, with a customer option to convert to a fixed capacity purchase at the end of year 10.
6. INCOME TAXES
Details of the federal and state income tax provisions are as follows:
2002 2001 ---------------------------- (in thousands) Total provision for income taxes: Federal: Current $26,990 $ 1,402 Deferred 2,338 3,017 - ------------------------------------------------------------- 29,238 4,419 - ------------------------------------------------------------- State: Current 4,622 240 Deferred 401 517 State manufacturer's tax credits (5,804) (2,665) - ------------------------------------------------------------- (781) (1,908) - ------------------------------------------------------------- Total $28,457 $ 2,511 =============================================================
Southern Power recorded a reduction in 2002 and 2001 tax expense of approximately $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 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. Southern Power'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.
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
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NOTES (continued) Southern Power Company 2002 Annual Report
2002 2001 ----------------------- (in millions) Deferred tax liabilities: Accelerated depreciation $(17,401) $(4,444) Other (729) (3,451) - -------------------------------------------------------------- Total (18,130) (7,895) - -------------------------------------------------------------- Deferred tax assets: Book/tax basis difference on asset transfer 15,644 19,810 Levelized capacity revenues 8,003 - Other comprehensive on interest rate swaps 30,745 - Other 2,329 - - -------------------------------------------------------------- Total 56,721 19,810 - -------------------------------------------------------------- Accumulated deferred income taxes in the consolidated Balance Sheets $38,591 $11,915 ==============================================================
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. Southern Power has recognized a payable to Georgia Power for Georgia Power's deferred tax liability resulting from this gain of approximately $15.6 million and $19.8 million at December 31, 2002 and 2001, respectively, which is recorded in other deferred credits on the accompanying consolidated balance sheet.
A reconciliation of the federal statutory tax rate to the effective income tax rate is as follows:
2002 2001 ------------------ Federal statutory rate 35.0 35.0 State income tax, net of federal deduction 3.9 4.6 State manufacturer's tax Credits, net of federal effect (4.5) (16.2) - ------------------------------------------------------- Effective income tax rate 34.4 23.4 =======================================================
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 Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability.
7. FINANCING
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 Southern Power's securities or obligations. Southern Power has SEC approval under the PUHCA to issue up to an aggregate amount of $2.5 billion of preferred securities, long and short-term debt and other equity issuances.
Common Stock
Southern Power has authorized common stock of 1 million shares at $.01 par value per share. One thousand shares have been issued to Southern Company and were outstanding at December 31, 2002.
Note Payable to Parent
In 2001, Southern Power entered into an intercompany note payable to Southern Company. The note is payable on demand and bears interest at a variable rate. At December 31, 2002 and 2001, $210.5 million and $1 million, respectively, were outstanding with an interest rate of 5.04% and 2.49%, respectively. As part of the Company's ongoing financing plan, in March 2003, $190 million of the note was converted to a capital contribution from Southern Company, leaving a balance of $51 million.
Long-Term Debt
In November 2001, the Company entered into an $850 million unsecured syndicated revolving credit facility (Facility). The purpose of the Facility is to finance the acquisition and construction costs related to gas-fired electric generating facilities and general corporate purposes (subject to a $25 million limit), and to pay or support commercial paper used to fund construction of facilities. At December 31, 2002, Southern Power had borrowed approximately $380 million under the Facility leaving an unused borrowing authority of approximately $470 million. Borrowings under the Facility bear interest at Southern Power's option equal to either the Eurodollar rate plus a specified margin ranging from 1.125% to 2.875%, depending on Southern Power's credit rating and the amount drawn down under the facility, or a base rate plus a specified margin. The interest rate
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NOTES (continued) Southern Power Company 2002 Annual Report
and average interest rate on the Facility were 2.73% and 3.15% and 3.44% and 3.61%, respectively, at December 31, 2002 and 2001 and during the periods then ended. Southern Power is required to pay a commitment fee on the unused balance of the Facility. The commitment fee ranges from 0.3% to 0.45%, depending on Southern Power's credit rating. For the periods ended December 31, 2002 and 2001, Southern Power paid approximately $1.1 million and $0.1 million in commitment fees, respectively. All borrowings outstanding under the Facility are due in November 2004.
The Facility contains certain financial covenants relating to Southern Power's debt capitalization which require that additional debt incurred by Southern Power must generally be unsecured and Southern Power 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 60% debt ratio, excluding intercompany loans. Southern Power was in compliance with such covenants at December 31, 2002. Initial borrowings under the Facility for new projects would be prohibited if Southern Power or Southern Company experiences a material adverse change (as defined in the Facility). For Southern Power's bank credit arrangements, there is a cross default to Southern Company's indebtedness, which if triggered would require prepayment of debt related to projects financed under the credit arrangement that are not complete.
In June 2002, Southern Power issued $575 million of 6.25% Senior Notes, Series A due July 15, 2012. The net proceeds were used to reduce outstanding indebtedness under the Facility and to reduce the intercompany note payable to Southern Company. Southern Power also settled several interest rate swap agreements entered into in anticipation of this issuance at a $16.9 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. Also in June 2002, the Company issued a long-term note payable to Chilton County, Alabama for $2.1 million. The proceeds of the note were used for the purchase of land for a potential future generation site. The note is payable over the next 5 years at an imputed interest rate of 6.25%.
Southern Company has committed to fund at least 40% of Southern Power's construction project financing and to pay for construction cost overruns to the extent that Southern Power's own cash flow is insufficient. Also, Southern Company will prepay any portion of revolving credit arrangements used for Southern Power's construction projects not completed within two years of the proposed completion date.
Financial Instruments
At December 31, 2002, Southern Power had $500 million notional amount of interest rate swaps outstanding with deferred losses of $63 million as follows:
Cash Flow Hedges
Weighted Average Fair Variable Fixed Value Rate Rate Notional Gain Maturity Received Paid Amount (Loss) - ------------------------------------------------------------------ (in millions) Southern Power 2013 * 6.23% $350 $(50) Southern Power 2008 * 5.48 150 (13) - ------------------------------------------------------------------ *Rate has not been set.
For the year 2002, approximately $0.9 million was reclassified from other comprehensive income to interest expense. These reclassifications related to losses incurred upon settlement of interest rate swaps associated with the issuance of senior notes in June 2002. (See "Long-Term Debt" herein). For the year 2003, approximately $1.7 million is expected to be reclassified.
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. The amount of commercial paper will initially represent about 45% of total debt, but is forecasted to decline to about 7% at year-end 2005 as increasingly more construction costs are refinanced with long-term securities.
The Company's commercial paper program is supported by the Facility. The Facility was structured to accommodate commercial paper, and the conditions that Southern Power 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.
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NOTES (continued) Southern Power Company 2002 Annual Report
8. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial information for 2002 and 2001 is as follows:
Operating Operating Quarter Ended Revenues Income Net Income - ------------------------------------------------------------------ (in millions) ----------------------------------------- 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
March 2001 $ - $ (107) $ (65) June 2001 - (1,569) (949) September 2001 14,604 7,056 5,957 December 2001 14,697 5,107 3,264 - ------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions. The Company's revenues initiated in July 2001 with the transfer of Plant Dahlberg and three related PPAs from Georgia Power.
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PART III
Items 10, 11, 12 and 13 for Southern Company are incorporated by reference in Southern Company's definitive Proxy Statement relating to the 2003 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 and "Certain Relationships and Related Transactions" for Item 13 for Southern Company.
Additionally, Items 10, 11, 12 and 13 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 2003 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 and "Certain Relationships and Related Transactions" for Item 13.
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, 2002.
SAVANNAH ELECTRIC
Identification of directors of Savannah Electric.
Anthony R. James President and Chief Executive Officer Age 52 Served as Director since 5-3-01
Gus H. Bell, III (1) Age 65 Served as Director since 7-20-99
Archie H. Davis (1) Age 61 Served as Director since 2-18-97
Walter D. Gnann (1) Age 67 Served as Director since 5-17-83
Robert B. Miller, III (1) Age 57 Served as Director since 5-17-83
Arnold M. Tenenbaum (1) Age 66 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, 2002) 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 52 Served as Executive Officer since 7-27-00
W. Miles Greer Vice President Age 59 Served as Executive Officer since 11-20-85
Sandra R. Miller Vice President Age 50 Served as Executive Officer since 7-26-01
Kirby R. Willis Vice President, Treasurer and Chief Financial Officer Age 51 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 25, 2002 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 selected as an officer, other than any arrangements or understandings with officers of Savannah Electric acting solely in their capacities as such.
III-1
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 a 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 - President and Director of Chatham Steel Corporation (specializing in carbon, stainless and specialty steel), Savannah, Georgia since January 2001. Previously served as President and Chief Executive Officer of Chatham Steel Corporation from 1981 to 2001. He serves on the advisory board of Wachovia 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 and Group Leader at Georgia Power's Plant Bowen from June 1996 to June 1998.
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).
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SOUTHERN POWER
Identification of directors of Southern Power.
W. Paul Bowers President and Chief Executive Officer Age 46 Served as Director since 5-1-01
H. Allen Franklin (1) Age 58 Served as Director since 1-8-01
Gale E. Klappa (1) Age 52 Served as Director since 5-8-01
Charles D. McCrary (1) Age 51 Served as Director since 2-11-02 and also served as Director from 1-8-01 to 4-16-01
David M. Ratcliffe (1) Age 54 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.
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 29, 2002) 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 46 Served as Executive Officer since 5-1-01
Robert G. Moore Senior Vice President Age 53 Served as Executive Officer since 1-4-02
Cliff S. Thrasher Senior Vice President, Comptroller and Chief Financial Officer Age 52 Served as Executive Officer since 6-10-02
Anthony J. Topazi Senior Vice President Age 52 Served as Executive Officer since 3-1-01
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 9, 2002 for the ensuing year, except for Mr. Thrasher 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.
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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; and Senior Vice President of Retail Marketing for Georgia Power from 1995 to 1998.
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 System companies - Southern Company, Alabama Power, Georgia Power and Gulf Power.
Gale E. Klappa - Executive Vice President, Chief Financial Officer and Treasurer of Southern Company since May 2001. Previously served as Financial Vice President, Chief Financial Officer and Treasurer of Southern Company from March 2001 to May 2001; Senior Vice President and Chief Strategic Officer of Southern Company from October 1999 to March 2001; President of Mirant's North America Group and Senior Vice President of Mirant from December 1998 to October 1999; and President and Chief Executive Officer of Western Power Distribution, a subsidiary of Mirant located in Bristol, England, from September 1995 to December 1998.
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 Banccorporation.
David M. Ratcliffe - 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; and Senior Vice President of Southern Company from March 1995 to March 1998. He is a director of Georgia Power; Mississippi Chemical Company; Federal Reserve Bank of Atlanta and CSX Corporation.
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.
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 - Senior Vice President since November 2002 and Vice President of SCS since December 1999. 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.
Section 16(a) Beneficial Ownership Reporting Compliance.
Not applicable.
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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 2002.
- --------------------------------------------- 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, 2000, 2001, and 2002, 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. The Southern Company Compensation and Management Succession Committee can increase the payout of performance dividends by up to 200 percent if necessary to maintain the competitiveness of Southern Company's executive compensation program. For eligible stock options held on December 31, 2000, 2001, and 2002, all named executives received a payout of $.90, $1.34, and $1.355 per option, respectively. The payout was not increased by the Committee. 3 Contributions in 2002 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 $7,696 $701 $3,838 W. Miles Greer 7,750 701 11,810 Kirby R. Willis 6,211 701 6,371 Sandra R. Miller 5,420 701 895 4 Mr. James became President and Chief Executive Officer effective May 1, 2001. 5 Ms. Miller became an executive officer of Savannah Electric on July 26, 2001.
III-5
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 2002.
- -------------------------- 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, 2000, 2001, and 2002, 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. The Southern Company Compensation and Management Succession Committee can increase the payout of performance dividends by up to 200 percent if necessary to maintain the competitiveness of Southern Company's executive compensation program. For eligible stock options held on December 31, 2000, 2001, and 2002, all named executives received a payout of $.90, $1.34, and $1.355 per option, respectively. The payout was not increased by the Committee. 8 Contributions in 2002 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 $7,701 $701 $8,400 $ - Anthony J. Topazi 7,709 701 5,864 - Robert G. Moore 7,683 701 2,886 2,626 Carson B. Harreld, Jr. 6,965 701 3,505 1,122 Cliff S. Thrasher 7,421 701 1,518 -
In 2002, these amounts include additional incentive compensation of $50,000 each for Mr. Topazi and Mr. Thrasher and $20,000 for Mr. Harreld. In 2001, these amounts included additional incentive compensation for Messrs. Bowers, Topazi and Harreld of $24,380, $200,000 and $100,000 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.Harreld ceased to be an executive officer of Southern Power effective June 9, 2002. On May 28, 2002, he was elected Senior Vice President of SCS.
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STOCK OPTION GRANTS IN 2002
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, 2002.
- ------------------------------------------ 11 Under the terms of the Omnibus Incentive Compensation Plan, stock option grants were made on February 15, 2002 and vest annually at a rate of one-third on the anniversary date of the grant. Grants fully vest upon termination as a result of death, total disability or retirement and expire five years after retirement, three years after death or total disability or their normal expiration date if earlier. The exercise price is the average of the high and low price of Southern Company's common stock on the date granted. Options may be transferred to certain family members, family trusts and family limited partnerships. 12 A total of 145,454 and 3,034,278 stock options were granted in 2002 to Savannah Electric and SCS, respectively. Southern Power has no employees; therefore, SCS employees perform work on behalf of Southern Power that is billed, at cost, to Southern Power. 13 Value was calculated using the Black-Scholes option valuation model. The actual value, if any, ultimately realized depends on the market value of Southern Company's common stock at a future date. Significant assumptions are shown below:
Risk-free Dividend Expected Volatility rate of return Yield Term - ------------------------------------------------------------------ 26.34% 2.79% 4.63% 4.28 years - ------------------------------------------------------------------
III-7
- --------------------------- 14 This column represents the excess of the fair market value of Southern Company's common stock of $28.39 per share, as of December 31, 2002, above the exercise price of the options. The Exercisable column reports the "value" of options that are vested and therefore could be exercised. The Unexercisable column reports the "value" of options that are not vested and therefore could not be exercised as of December 31, 2002.
15 The "Value Realized" is ordinary income, before taxes, and represents the amount equal to the excess of the fair market value of the shares at the time of exercise above the exercise price.
III-8
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 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-5 and III-6.
As of December 31, 2002, 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 $350,806 23 W. Miles Greer16 258,424 26 Kirby R. Willis 240,171 28 Sandra R. Miller 187,416 22
Southern Power
Compensation Accredited Name Level Years of Service ---- ----- ---------------- W. Paul Bowers $528,397 22 Anthony J. Topazi 414,272 32 Robert G. Moore 331,584 28 Carson B. Harreld, Jr.17 349,358 29 Cliff S. Thrasher 287,468 31
- ------------------------------ 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 10 years credited to Mr. Harreld pursuant to a supplemental pension agreement.
III-9
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 2002 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 2002 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, 2002 in addition to or in lieu of that specified by the standard arrangements specified above.
III-10
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.
Mr. Carson B. Harreld, Jr. and Georgia Power, Southern Company and SCS entered into an agreement that provides for a monthly payment to Mr. Harreld after his retirement equal to the difference between the amount he will receive under the Southern Company Pension Plan and the amount he would receive under the Plan had he been employed by the Southern Company system an additional 10 years.
Report on Repricing of Options. - ------------------------------- None.
Compensation Committee Interlocks and Insider Participation. - ------------------------------------------------------------ None.
III-11
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
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. Amount and Name and Address Nature of Percent of Beneficial Beneficial of Title of Class Owner Ownership Class - --------------------------------------------------------------------------------
Common Stock The Southern Company 100% 270 Peachtree Street, N.W. Atlanta, Georgia 30303
Registrants: Savannah Electric 10,844,635 Southern Power 1,000
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, 2002. 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, 2002.
III-12
(1) As used in the tables, "beneficial ownership" means the sole or shared power to vote, or to direct the voting of, a security and/or investment power with respect to a security (i.e., the power to dispose of, or to direct the disposition of, a security).
(2) Indicates shares of Southern Company common stock that directors and executive officers have the right to acquire within 60 days.
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-13
Equity Compensation Plan Information
The following table provides information as of December 31, 2002 concerning shares of Southern Company common stock authorized for issuance under Southern Company's existing non-qualified equity compensation plans.
(1) Includes securities available for future issuance under the Omnibus Incentive Compensation Plan (46,789,131) and the Outside Directors Stock Plans (1,770,788).
III-14
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
SAVANNAH ELECTRIC
Transactions with management and others.
Mr. Archie Davis is currently Vice Chairman 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. During 2002, 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.
ITEM 14.
ITEM 14. CONTROLS AND PROCEDURES
(a) Evaluation of disclosure controls and procedures.
Within 90 days of the filing date of this annual report, Southern Company, the 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-14(c) and 15d-14(c) 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 significant changes in Southern Company's, the operating companies' or Southern Power's internal controls or in other factors that could significantly affect these internal controls subsequent to the date each company carried out its evaluation.
III-15
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-23, IV-25, IV-27, IV-29, IV-31, IV-33 and IV-35.
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-24, IV-26, IV-28, IV-30, IV-32 and IV-34.
(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 2002 were as follows:
Southern Company filed a Current Report on Form 8-K:
Date of event: November 25, 2002 Item reported: 5
Alabama Power filed Current Reports on Form 8-K:
Date of event: October 16, 2002 Items reported: 5 and 7
Date of event: November 20, 2002 Items reported: 5 and 7
Date of event: December 6, 2002 Items reported: 5 and 7
Georgia Power filed Current Reports on Form 8-K:
Date of event: October 30, 2002 Items reported: 5 and 7
Date of event: November 15, 2002 Items reported: 5 and 7
Gulf Power filed a Current Report on Form 8-K:
Date of event: December 5, 2002 Items reported: 5 and 7
Savannah Electric filed a Current Report on Form 8-K:
Date of event: November 4, 2002 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 7, 2003
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)
Gale E. Klappa 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 Donald M. James Dorrit J. Bern Zack T. Pate Thomas F. Chapman J. Neal Purcell L. G. Hardman III Gerald J. St. Pe'
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
IV-2
THE SOUTHERN COMPANY
Certification Of Chief Executive Officer Per Section 302 Of The Sarbanes-Oxley Act
I, Allen Franklin, certify that:
1. I have reviewed this annual report on Form 10-K of The Southern Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 7, 2003 /s/ Allen Franklin ----------------------------------- Allen Franklin Chairman and Chief Executive Officer
IV-3
THE SOUTHERN COMPANY
Certification Of Chief Financial Officer Per Section 302 Of The Sarbanes-Oxley Act
I, Gale E. Klappa, certify that:
1. I have reviewed this annual report on Form 10-K of The Southern Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 7, 2003 /s/ Gale E. Klappa ----------------------------------- Gale E. Klappa Executive Vice President, Chief Financial Officer and Treasurer
IV-4
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 7, 2003
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 Mayer Mitchell David J. Cooper Robert D. Powers H. Allen Franklin C. Dowd Ritter R. Kent Henslee James H. Sanford Carl E. Jones, Jr. John Cox Webb, IV Patricia M. King James W. Wright James K. Lowder Wallace D. Malone, Jr.
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
IV-5
ALABAMA POWER COMPANY
Certification Of Chief Executive Officer Per Section 302 Of The Sarbanes-Oxley Act
I, Charles D. McCrary, certify that:
1. I have reviewed this annual report on Form 10-K of Alabama Power Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 7, 2003 /s/ Charles D. McCrary ----------------------------------- Charles D. McCrary President and Chief Executive Officer
IV-6
ALABAMA POWER COMPANY
Certification Of Chief Financial Officer Per Section 302 Of The Sarbanes-Oxley Act
I, William B. Hutchins, III, certify that:
1. I have reviewed this annual report on Form 10-K of Alabama Power Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 7, 2003 /s/ William B. Hutchins, III ----------------------------------- William B. Hutchins, III Executive Vice President, Chief Financial Officer and Treasurer
IV-7
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, President and Chief Executive Officer
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
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 President, Chief Executive Officer and Director (Principal Executive Officer)
Allen L. Leverett 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 Richard W. Ussery Anna R. Cablik William Jerry Vereen H. Allen Franklin Carl Ware L. G. Hardman III E. Jenner Wood, III G. Joseph Prendergast
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
IV-8
GEORGIA POWER COMPANY
Certification Of Chief Executive Officer Per Section 302 Of The Sarbanes-Oxley Act
I, David M. Ratcliffe, certify that:
1. I have reviewed this annual report on Form 10-K of Georgia Power Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 7, 2003 /s/ David M. Ratcliffe ----------------------------------- David M. Ratcliffe President and Chief Executive Officer
IV-9
GEORGIA POWER COMPANY
Certification Of Chief Financial Officer Per Section 302 Of The Sarbanes-Oxley Act
I, Allen L. Leverett, certify that:
1. I have reviewed this annual report on Form 10-K of Georgia Power Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 7, 2003 /s/ Allen L. Leverett ----------------------------------- Allen L. Leverett Executive Vice President, Chief Financial Officer and Treasurer
IV-10
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: Thomas A. Fanning, President and Chief Executive Officer
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
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.
Thomas A. Fanning 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 H. Allen Franklin William C. Cramer, Jr. William A. Pullum Fred C. Donovan, Sr. Joseph K. Tannehill
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
IV-11
GULF POWER COMPANY
Certification Of Chief Executive Officer Per Section 302 Of The Sarbanes-Oxley Act
I, Thomas A. Fanning, certify that:
1. I have reviewed this annual report on Form 10-K of Gulf Power Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 7, 2003 /s/ Thomas A. Fanning ----------------------------------- Thomas A. Fanning President and Chief Executive Officer
IV-12
GULF POWER COMPANY
Certification Of Chief Financial Officer Per Section 302 Of The Sarbanes-Oxley Act
I, Ronnie R. Labrato, certify that:
1. I have reviewed this annual report on Form 10-K of Gulf Power Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 7, 2003 /s/ Ronnie R. Labrato ----------------------------------- Ronnie R. Labrato Vice President, Chief Financial Officer and Comptroller
IV-13
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: Michael D. Garrett, President and Chief Executive Officer
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
Michael D. Garrett President, Chief Executive Officer and Director (Principal Executive Officer)
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 7, 2003
IV-14
MISSISSIPPI POWER COMPANY
Certification Of Chief Executive Officer Per Section 302 Of The Sarbanes-Oxley Act
I, Michael D. Garrett, certify that:
1. I have reviewed this annual report on Form 10-K of Mississippi Power Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 7, 2003 /s/ Michael D. Garrett ----------------------------------- Michael D. Garrett President and Chief Executive Officer
IV-15
MISSISSIPPI POWER COMPANY
Certification Of Chief Financial Officer Per Section 302 Of The Sarbanes-Oxley Act
I, Michael W. Southern, certify that:
1. I have reviewed this annual report on Form 10-K of Mississippi Power Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 7, 2003 /s/ Michael W. Southern ----------------------------------- Michael W. Southern Vice President, Chief Financial Officer and Treasurer
IV-16
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 7, 2003
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 7, 2003
IV-17
SAVANNAH ELECTRIC AND POWER COMPANY
Certification Of Chief Executive Officer Per Section 302 Of The Sarbanes-Oxley Act
I, Anthony R. James, certify that:
1. I have reviewed this annual report on Form 10-K of Savannah Electric and Power Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 7, 2003 /s/ Anthony R. James ----------------------------------- Anthony R. James President and Chief Executive Officer
IV-18
SAVANNAH ELECTRIC AND POWER COMPANY
Certification Of Chief Financial Officer Per Section 302 Of The Sarbanes-Oxley Act
I, Kirby R. Willis, certify that:
1. I have reviewed this annual report on Form 10-K of Savannah Electric and Power Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 7, 2003 /s/ Kirby R. Willis ----------------------------------- Kirby R. Willis Vice President, Chief Financial Officer and Treasurer
IV-19
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 7, 2003
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: H. Allen Franklin Charles D. McCrary Gale E. Klappa David M. Ratcliffe
By: Wayne Boston (Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
IV-20
SOUTHERN POWER COMPANY
Certification Of Chief Executive Officer Per Section 302 Of The Sarbanes-Oxley Act
I, William P. Bowers, certify that:
1. I have reviewed this annual report on Form 10-K of Southern Power Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 7, 2003 /s/ William P. Bowers ----------------------------------- William P. Bowers President and Chief Executive Officer
IV-21
SOUTHERN POWER COMPANY
Certification Of Chief Financial Officer Per Section 302 Of The Sarbanes-Oxley Act
I, Cliff S. Thrasher, certify that:
1. I have reviewed this annual report on Form 10-K of Southern Power Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 7, 2003 /s/ Cliff S. Thrasher ----------------------------------- Cliff S. Thrasher Senior Vice President, Comptroller and Chief Financial Officer
IV-22
Deloitte & Touche LLP 191 Peachtree Street, NE Suite 1500 Atlanta, Georgia 30303-1924
www.deloitte.com
Deloitte & Touche
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 and for the year ended December 31, 2002, and have issued our report thereon dated February 17, 2003; such consolidated financial statement and report are included elsewhere in this Form 10-K. Our audit also included the consolidated financial statement schedule of Southern Company and Subsidiary Companies (page S-2) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of Southern Company's management. Our responsibility is to express an opinion based on our audit. The consolidated financial statement schedules of Southern Company and Subsidiary Companies as of December 31, 2001 and 2000 and for the two years then ended were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, in their report dated February 13, 2002. In our opinion, the consolidated financial statement schedule as of and for the year ended December 31, 2002, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia February 17, 2003
IV-23
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-24
Deloitte & Touche LLP Suite 1000 417 North 20th Street Birmingham, Alabama 35203-3289
www.deloitte.com
Deloitte & Touche
INDEPENDENT AUDITORS' REPORT
Alabama Power Company:
We have audited the financial statements of Alabama Power Company as of and for the year ended December 31, 2002, and have issued our report thereon dated February 17, 2003; such financial statements and report are included elsewhere in this Form 10-K. Our audit also included the financial statement schedule of Alabama Power Company (page S-3) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of Alabama Power Company's management. Our responsibility is to express an opinion based on our audit. The financial statement schedules of Alabama Power Company as of December 31, 2001 and 2000 and for the two years then ended were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statement schedules, when considered in relation to the basic financial statements taken as a whole, in their report dated February 13, 2002. In our opinion, the financial statement schedule as of and for the year ended December 31, 2002, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Birmingham, Alabama February 17, 2003
IV-25
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-26
Deloitte & Touche LLP 191 Peachtree Street, NE Suite 1500 Atlanta, Georgia 30303-1924
www.deloitte.com
Deloitte & Touche
INDEPENDENT AUDITORS' REPORT
Georgia Power Company:
We have audited the financial statements of Georgia Power Company as of and for the year ended December 31, 2002, and have issued our report thereon dated February 17, 2003; such financial statements and report are included elsewhere in this Form 10-K. Our audit also included the financial statement schedule of Georgia Power Company (page S-4) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of Georgia Power Company's management. Our responsibility is to express an opinion based on our audit. The financial statement schedules of Georgia Power Company as of December 31, 2001 and 2000 and for the two years then ended were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statement schedules, when considered in relation to the basic financial statements taken as a whole, in their report dated February 13, 2002. In our opinion, the financial statement schedule as of and for the year ended December 31, 2002, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia February 17, 2003
IV-27
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-28
Deloitte & Touche LLP 191 Peachtree Street, NE Suite 1500 Atlanta, Georgia 30303-1924
www.deloitte.com
Deloitte & Touche
INDEPENDENT AUDITORS' REPORT
Gulf Power Company:
We have audited the financial statements of Gulf Power Company as of and for the year ended December 31, 2002, and have issued our report thereon dated February 17, 2003; such financial statements and report are included elsewhere in this Form 10-K. Our audit also included the financial statement schedule of Gulf Power Company (page S-5) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of Gulf Power Company's management. Our responsibility is to express an opinion based on our audit. The financial statement schedules of Gulf Power Company as of December 31, 2001 and 2000 and for the two years then ended were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statement schedules, when considered in relation to the basic financial statements taken as a whole, in their report dated February 13, 2002. In our opinion, the financial statement schedule as of and for the year ended December 31, 2002, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia February 17, 2003
IV-29
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-30
Deloitte & Touche LLP 191 Peachtree Street, NE Suite 1500 Atlanta, Georgia 30303-1924
www.deloitte.com
Deloitte & Touche
INDEPENDENT AUDITORS' REPORT
Mississippi Power Company:
We have audited the financial statements of Mississippi Power Company as of and for the year ended December 31, 2002, and have issued our report thereon dated February 17, 2003; such financial statements and report are included elsewhere in this Form 10-K. Our audit also included the financial statement schedule of Mississippi Power Company (page S-6) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of Mississippi Power Company's management. Our responsibility is to express an opinion based on our audit. The financial statement schedules of Mississippi Power Company as of December 31, 2001 and 2000 and for the two years then ended were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statement schedules, when considered in relation to the basic financial statements taken as a whole, in their report dated February 13, 2002. In our opinion, the financial statement schedule as of and for the year ended December 31, 2002, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia February 17, 2003
IV-31
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-32
Deloitte & Touche LLP 191 Peachtree Street, NE Suite 1500 Atlanta, Georgia 30303-1924
www.deloitte.com
Deloitte & Touche
INDEPENDENT AUDITORS' REPORT
Savannah Electric and Power Company:
We have audited the financial statements of Savannah Electric and Power Company as of and for the year ended December 31, 2002, and have issued our report thereon dated February 17, 2003; such financial statements and report are included elsewhere in this Form 10-K. Our audit also included the financial statement schedule of Savannah Electric and Power Company (page S-7) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of Savannah Electric and Power Company's management. Our responsibility is to express an opinion based on our audit. The financial statement schedules of Savannah Electric and Power Company as of December 31, 2001 and 2000 and for the two years then ended were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statement schedules, when considered in relation to the basic financial statements taken as a whole, in their report dated February 13, 2002. In our opinion, the financial statement schedule as of and for the year ended December 31, 2002, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia February 17, 2003
IV-33
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-34
Deloitte & Touche LLP 191 Peachtree Street, NE Suite 1500 Atlanta, Georgia 30303-1924
www.deloitte.com
Deloitte & Touche
INDEPENDENT AUDITORS' REPORT
Southern Power Company:
We have audited the financial statements of Southern Power Company as of December 31, 2002 and 2001, and for the year ended December 31, 2002 and for the period from January 8, 2001 (inception) to December 31, 2001, and have issued our report thereon dated February 17, 2003; 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 February 17, 2003
IV-35
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule Page
II Valuation and Qualifying Accounts and Reserves 2002, 2001 and 2000 The Southern Company and Subsidiary Companies................. S-2 Alabama Power Company......................................... S-3 Georgia Power Company......................................... S-4 Gulf Power Company............................................ S-5 Mississippi Power Company..................................... S-6 Savannah Electric and Power Company........................... S-7
Valuation and Qualifying Accounts and Reserves 2002 and 2001 Southern Power Company........................................ S-8
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