ITEM 1. BUSINESS.
Tampa Electric Company (the company) was incorporated in Florida in 1899 and was reincorporated in 1949. As a result of a restructuring in 1981, the company became a wholly owned subsidiary of TECO Energy, Inc. (TECO Energy), a diversified energy-related holding company.
In 1997, TECO Energy acquired Lykes Energy, Inc. As part of this acquisition, Lykes' regulated gas distribution utility was merged into the company and now operates as the Peoples Gas System division of Tampa Electric Company (Peoples Gas System or PGS). Also in June 1997, TECO Energy completed its acquisition of West Florida Natural Gas Company (West Florida Gas), a local distribution company, serving the Ocala and Panama City, Florida areas. West Florida Gas now operates as part of the Peoples Gas System division.
Tampa Electric Company is a public utility operating within the state of Florida. Through its Tampa Electric division (Tampa Electric), it is engaged in the generation, purchase, transmission, distribution and sale of electric energy; through its Peoples Gas System division, it is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers wholly in the State of Florida.
Tampa Electric's retail electric service territory comprises an area of about 2,000 square miles in West Central Florida, including Hillsborough County and parts of Polk, Pasco and Pinellas Counties, and has an estimated population of over one million. Tampa Electric provides electric service to more than 552,000 customers. The principal communities served are Tampa, Winter Haven, Plant City and Dade City. In addition, Tampa Electric engages in wholesale sales to utilities and other resellers of electricity. It has three electric generating stations in or near Tampa, one electric generating station in southwestern Polk County, Florida and two electric generating stations (one of which is on long-term standby) located near Sebring, a city located in Highlands County in South Central Florida.
PGS, with approximately 253,000 customers, has operations in Florida's major metropolitan areas. Annual natural gas throughput (the amount of gas delivered to its customers including transportation only service) in 1999 was 1.1 billion therms.
Power Engineering & Construction, Inc. (PEC), a Florida corporation formed in late 1996, is a wholly owned subsidiary of Tampa Electric Company and is engaged in engineering and construction services with principal focus on power facilities not owned or operated by Tampa Electric. Operations of PEC in 1999 were not significant.
TAMPA ELECTRIC--ELECTRIC OPERATIONS
Tampa Electric had 2,850 employees as of Dec. 31, 1999, of which 1,067 were represented by the International Brotherhood of Electrical Workers (IBEW) and 345 by the Office and Professional Employees International Union.
In 1999, approximately 46 percent of Tampa Electric's total operating revenue was derived from residential sales, 29 percent from commercial sales, 9 percent from industrial sales and 16 percent from other sales including bulk power sales for resale.
The sources of electric operating revenue and megawatt-hour sales for 1999 were as follows:
No significant part of Tampa Electric's business is dependent upon a single customer or a few customers, the loss of any one or more of whom would have a significantly adverse effect on Tampa Electric, except for IMC-Agrico (IMCA), a large phosphate producer representing less than 3 percent of Tampa Electric's 1999 base revenues.
Tampa Electric's business is not highly seasonal, but winter peak loads are experienced due to fewer daylight hours and colder temperatures, and summer peak loads are experienced due to use of air conditioning and other cooling equipment.
REGULATION
The retail operations of Tampa Electric are regulated by the Florida Public Service Commission (FPSC), which has jurisdiction over retail rates, quality of service, issuances of securities, planning, siting and construction of facilities, accounting and depreciation practices and other matters.
In general, the FPSC's pricing objective is to set rates at a level that allows the utility to collect total revenues (revenue requirements) equal to its cost of providing service, including a reasonable return on invested capital.
The costs of owning, operating and maintaining the utility system, other than fuel, purchased power, conservation and certain environmental costs, are recovered through base rates. These costs include operation and maintenance expenses, depreciation and taxes, as well as a return on Tampa Electric's investment in assets used and useful in providing electric service (rate base). The rate of return on rate base, which is intended to approximate Tampa Electric's weighted cost of capital, primarily includes its costs for debt, deferred income taxes at a zero cost rate and an allowed return on common equity. Base prices are determined in FPSC price setting hearings which occur at irregular intervals at the initiative of Tampa Electric, the FPSC or other parties. See the discussion of the FPSC-approved agreements covering 1995 through 1999 on pages 17 and 18.
Fuel, conservation, certain environmental and certain purchased power costs are recovered through levelized monthly charges established pursuant to the FPSC's cost recovery clauses. These charges, which are reset annually in an FPSC proceeding, are based on estimated costs of fuel, environmental compliance, conservation programs and purchased power and estimated customer usage for a specific recovery period, with a true-up adjustment to reflect the variance of actual costs from the projected charges.
The FPSC may disallow recovery of any costs that it considers imprudently incurred.
Tampa Electric is also subject to regulation by the Federal Energy Regulatory Commission (FERC) in various respects including wholesale power sales, certain wholesale power purchases, transmission services and accounting and depreciation practices.
Federal, state and local environmental laws and regulations cover air quality, water quality, land use, power plant, substation and transmission line siting, noise and aesthetics, solid waste and other environmental matters. See ENVIRONMENTAL MATTERS on pages 5 and 6.
TECO Transport Corporation (TECO Transport), TECO Coal Corporation (TECO Coal) and TECO Power Services Corporation (TECO Power Services), subsidiaries of TECO Energy, sell transportation services, coal, and generating capacity and energy, respectively, to Tampa Electric in addition to third parties. The transactions between Tampa Electric and these affiliates and the prices paid by Tampa Electric are subject to regulation by the FPSC and FERC, and any charges deemed to be imprudently incurred may not be allowed to be recovered from Tampa Electric's customers.
COMPETITION
Tampa Electric's retail electric business is substantially free from direct competition with other electric utilities, municipalities and public agencies. At the present time, the principal form of competition at the retail level consists of natural gas and propane for residential and commercial customers and the self-generation option is available to larger users of electric energy. Such users may seek to expand their options through various initiatives including legislative and/or regulatory changes that would permit competition at the retail level. Tampa Electric intends to take all appropriate actions to retain and expand its retail business, including managing costs and providing high-quality service to retail customers.
In 1999, the FERC approved a market-based sales tariff for Tampa Electric which allows Tampa Electric to sell excess power at market prices. The FERC had already approved market-based prices for interstate sales for Tampa Electric and the other state investor owned utilities (IOU's); however, Tampa Electric is the only utility with intrastate market-based sales authority.
There is presently active competition in the wholesale power markets in Florida, and this is increasing largely as a result of the Energy Policy Act of 1992 and related federal initiatives. This Act removed for independent power producers certain regulatory barriers and required utilities to transmit power from such producers, utilities and others to wholesale customers as more fully described below.
In April 1996, the FERC issued its Final Rule on Open Access Non-discriminatory Transmission, Stranded Costs, Open Access Same-time Information System (OASIS) and Standards of Conduct. These rules work together to open access for wholesale power flows on transmission systems. Utilities such as Tampa Electric owning transmission facilities are required to provide services to wholesale transmission customers comparable to those they provide to themselves on comparable terms and conditions including price. Among other things, the rules require transmission services to be unbundled from power sales and owners of transmission systems must take transmission service under their own transmission tariffs.
Transmission system owners are also required to implement an OASIS system providing, via the Internet, access to transmission service information (including price and availability), and to rely exclusively on their own OASIS system for such
information for purposes of their own wholesale power transactions. To facilitate compliance, owners must implement Standards of Conduct to ensure that personnel involved in marketing wholesale power are functionally separated from personnel involved in transmission services and reliability functions. Tampa Electric, together with other utilities, has implemented an OASIS system and believes it is in compliance with the Standards of Conduct.
In addition to these transmission developments at the federal level, there have been initiatives at the state level to facilitate the construction of merchant power plants, i.e. plants built on speculation with a portion or all of their capacity not subject to purchase agreements. Tampa Electric has opposed these efforts. See WHOLESALE POWER MARKET on 19 for a further description of proposed projects and the issues involved.
FUEL
About 97 percent of Tampa Electric's generation for 1999 was from its coal-fired units which provided approximately 86 percent of the Company's total system energy requirements. About the same level is anticipated for 2000.
Tampa Electric's average delivered fuel cost per million BTU and average delivered cost per ton of coal burned for 1999 were as follows:
Tampa Electric's generating stations burn fuels as follows: Gannon Station burns low-sulfur coal; Big Bend Station, which has sulfur dioixide scrubber capabilities, burns a combination of low-sulfur coal and coal of a somewhat higher sulfur content; Polk Power Station burns high-sulfur coal which is gasified subject to sulfur removal prior to combustion; Hookers Point Station burns low-sulfur oil; Phillips Station burns oil of a somewhat higher sulfur content; and Dinner Lake Station, which was placed on long-term reserve standby in March 1994, burned natural gas and oil.
COAL. Tampa Electric used approximately 7.3 million tons of coal during 1999 and estimates that its coal consumption will be about 7.9 million tons for 2000. During 1999, Tampa Electric purchased approximately 64 percent of its coal under long-term contracts with six suppliers, including TECO Coal, and 36 percent of its coal in the spot market or under intermediate-term purchase agreements. During December 1999, the average delivered cost of all coal delivered (including transportation) was $44.35 per ton, or $1.88 per million BTU. About 8 percent of Tampa Electric's 1999 coal requirements were supplied by TECO Coal. Tampa Electric's long-term contract with TECO Coal expired at the end of 1999 and will not be renewed. Tampa Electric expects to obtain approximately 53 percent of its coal requirements in 2000 under long-term contracts with five suppliers and the remaining 47 percent in the spot market or under intermediate-term purchase agreements. Tampa Electric's remaining long-term coal contracts provide for revisions in the base price to reflect changes in a wide range of cost factors and for suspension or reduction of deliveries if environmental regulations should prevent Tampa Electric from burning the coal supplied, provided that a good faith effort has been made to continue burning such coal.
In 1999, about 67 percent of Tampa Electric's coal supply was deep-mined, approximately 32 percent was surface-mined and the remainder was a processed oil by-product known as petroleum coke. Federal surface-mining laws and regulations have not had any material adverse impact on Tampa Electric's coal supply or results of its operations. Tampa Electric, however, cannot predict the effect on the market price of coal of any future mining laws and regulations. Although there are reserves of surface-mineable coal dedicated by suppliers to Tampa Electric's account, high-quality coal reserves in Kentucky that can be economically surface-mined are being depleted and in the future more coal will be deep-mined. This trend is not expected to result in any significant additional costs to Tampa Electric.
OIL. Tampa Electric had supply agreements through Dec. 31, 1999 for No. 2 fuel oil and No. 6 fuel oil for its Polk and Hookers Point stations, and its four combustion turbine units at prices based on Gulf Coast Cargo spot prices. Contracts for the supply of No. 6 fuel oil through Dec. 31, 2000 are expected to be finalized by March 31, 2000. The price for No. 2 fuel oil deliveries taken in December 1999 was $30.14 per barrel, or $5.20 per million BTU. There were no No. 6 fuel oil deliveries taken in December 1999.
FRANCHISES
Tampa Electric holds franchises and other rights that, together with its charter powers, give it the right to carry on its retail business in the localities it serves. The franchises are irrevocable and are not subject to amendment without the consent of Tampa Electric, although, in certain events, they are subject to forfeiture.
Florida municipalities are prohibited from granting any franchise for a term exceeding 30 years. If a franchise is not renewed by a municipality, the franchisee may choose to exercise its statutory right to require the municipality to purchase any and all property used in connection with the franchise at a valuation to be fixed by arbitration or, if arbitration is unsuccessful, by eminent domain. In addition, all of the municipalities except for the cities of Tampa and Winter Haven have reserved the right to purchase Tampa Electric's property used in the exercise of its franchise, if the franchise is not renewed.
Tampa Electric has franchise agreements with 13 incorporated municipalities within its retail service area. These agreements have various expiration dates ranging from December 2005 to September 2021.
Franchise fees payable by Tampa Electric, which totaled $20.8 million in 1999, are calculated using a formula based primarily on electric revenues.
Utility operations in Hillsborough, Pasco, Pinellas and Polk Counties outside of incorporated municipalities are conducted in each case under one or more permits to use county rights-of-way granted by the county commissioners of such counties. There is no law limiting the time for which such permits may be granted by counties. There are no fixed expiration dates for the Hillsborough County and Pinellas County agreements. The agreements covering electric operations in Pasco and Polk counties expire in 2033 and 2005, respectively.
ENVIRONMENTAL MATTERS
Tampa Electric met the environmental compliance requirements for the Phase I emission limitations imposed by the Clean Air Act Amendments (CAAA) which became effective Jan. 1, 1995 by using blends of lower-sulfur coal, integrating the Big Bend Unit Four FGD system with Unit Three, implementing operational modifications and purchasing emission allowances. For Phase II, which began Jan. 1, 2000, further reductions in sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions were required. To comply with the Phase II SO2 requirements, the company installed a new FGD system at Big Bend Units One and Two and will rely less on fuel blending and SO2 allowance purchases. The $83 million scrubber was placed in service on Dec. 30, 1999 and will significantly reduce the amount of SO2 emitted by Tampa Electric's Big Bend Units One and Two. As a result of this project, all of the units at Big Bend Station, Tampa Electric's largest generating station, are equipped with FGD, or scrubber technology. The FPSC approved recovery of the costs associated with the Big Bend Units One and Two FGD system in November 1999 and cost recovery began in January 2000. In order to comply with the Phase II NOx emission limits on a system wide average, Tampa Electric has implemented combustion optimization projects at Big Bend and Gannon Stations.
In 1997, the EPA began an investigation under the Clean Air Act (CAA) of coal-fired electric power generators to determine compliance with New Source Review (NSR) environmental permitting requirements associated with repairs, maintenance, modifications and operational changes made to the facilities over the years. The EPA asserted that certain electric utilities, including Tampa Electric, should have applied for pre-construction permits for certain unit maintenance projects, and that the permitting review of such projects would have included NSR, resulting in requirements that the units meet more restrictive, Best Available Control Technology (BACT) standards for NOx, SO2 and particulate matter (PM). Tampa Electric disagreed with EPA's interpretation of its NSR rules and its definitions of what constitutes maintenance. On Nov. 3, 1999, despite Tampa Electric's extensive efforts to reach a mutually agreeable settlement with the EPA, the Department of Justice sued Tampa Electric and six other electric utilities and issued an administrative order against TVA on behalf of the EPA for alleged violations of the CAA associated with this NSR issue. Coincident with the lawsuits, EPA issued Notices of Violations (NOV) alleging similar NSR violations under the relevant State Implementation Plans (SIP).
Following notice to the State of Florida of the EPA's NOV, the Florida Department of Environmental Protection (DEP), the agency responsible for enforcement of the Air Quality SIP, began negotiations to resolve the same allegations under the SIP that Tampa Electric had not applied for appropriate permits for certain unit maintenance projects at Gannon and Big Bend Stations and, therefore, had operated the coal-fired units without BACT for NOx and SO2. Effective Dec. 16, 1999, a Consent Final Judgment (CFJ) entered into between DEP and Tampa Electric resolved the DEP claims. The requirements of the CFJ require the implementation of several environmental initiatives which include repowering certain Gannon Station units with natural gas and placing the remaining Gannon units on reserve standby by the end of 2004. It also requires Tampa Electric to implement other specific initiatives to further reduce NOx, SO2 and PM emissions at Big Bend Station Unit Four by 2007 and Big Bend Units One, Two and Three by 2010.
On Feb. 29, 2000, Tampa Electric Company, the U.S. Environmental Protection Agency and the U.S. Department of Justice announced they had resolved the federal agencies' pending enforcement actions (including the NOV) filed last year against the company. The resolution, which was in the form of a consent decree, resulted in full and final settlement of the November 1999 federal litigation and NOV alleging violations of NSR requirements of the Clear Air Act. The consent decree was lodged with the U.S. District Court for the Middle District of Florida in Tampa, Florida, and, is subject to a 30-day public comment period before it may be entered by the Court at which time it will become effective.
The agreement is substantially the same as Tampa Electric's earlier agreement with the Florida Department of Environmental Protection with respect to environmental controls and pollution reductions reached on Dec. 7, 1999; however, it contains specific detail with respect to the availability of the scrubbers and earlier incremental NOx reduction efforts on Big Bend Units One, Two and Three. In order to eliminate the uncertainties of litigation and in exchange for a release from past liability and a safe harbor during the 10-year term of the consent decree, the Company agreed to pay a $3.5 million civil penalty. Under the consent decree,
Tampa Electric will commit to a comprehensive cleanup program that will dramatically decrease emissions from the company's power plants. The agreement makes Tampa Electric the first utility in the nation to respond to EPA's coal-fired utility initiative.
Engineering for the repowering project began in January 2000, and the company anticipates that commercial operation for the first repowered unit will occur by May 1, 2003. The repowering of additional units is scheduled to be completed by May 1, 2004. When these units are repowered, the station will be renamed the Bayside Power Station and will have an increased total station capacity of about 1,475 megawatts of natural gas-fueled electric energy.
Tampa Electric Company is a potentially responsible party for certain superfund sites and, through its Peoples Gas System division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, Tampa Electric Company estimates its ultimate financial liability at approximately $20 million over the next 10 years. The environmental remediation costs associated with these sites are not expected to have a significant impact on customer prices.
EXPENDITURES. During the five years ended Dec. 31, 1999, Tampa Electric spent $212.2 million on capital additions to meet environmental requirements including $92.8 million for the Polk Power Station project. Environmental expenditures are estimated at $6.4 million for 2000 and $17.3 million in total for 2001 through 2004. These totals exclude amounts required to comply with the CAAA, as discussed in the following paragraphs.
Tampa Electric is complying with the Phase I emission limitations imposed by the CAAA which became effective Jan. 1, 1995 by using blends of lower-sulfur coal, controlling stack emissions and purchasing emission allowances.
In December 1999, Tampa Electric put into operation a flue gas desulfurization (FGD) system or "scrubber" at Big Bend Units One and Two. As a result of the installation of this FGD system, all of the units at Big Bend Station, Tampa Electric's largest generating station, will be equipped with scrubber technology. This technology will reduce the sulfur dioxide emissions from these units and will allow Tampa Electric to achieve compliance with the requirements of the Clean Air Act Amendments. As of Dec. 31, 1999, Tampa Electric had spent approximately $80 million on the FGD project, and it expects the total expenditures for the scrubber to be about $83 million.
The FPSC approved the FGD system as the most cost effective alternative for Tampa Electric to meet its CAAA compliance requirements and the recovery of prudently incurred costs through the environmental cost recovery clause. Cost recovery began in January 2000.
Tampa Electric may petition the FPSC for recovery of certain other environmental compliance costs on a current basis pursuant to a statutory environmental cost recovery procedure used in connection with the above described FGD system, along with environmental costs required by the consent decree described above.
In 1999, Tampa Electric recovered $8 million of environmental compliance costs through the environmental cost recovery clause. These were costs incurred by Tampa Electric after April 1993 to comply with environmental regulations that were not included in the then current base rates. In addition, Tampa Electric may recover environmental compliance costs through base rates.
PEOPLES GAS SYSTEM--GAS OPERATIONS
PGS is engaged in the purchase, distribution and marketing of natural gas for residential, commercial, industrial and electric power generation customers in the State of Florida.
PGS has no gas reserves, but relies on two interstate pipelines to deliver gas to it for sale or other delivery to customers connected to its distribution system. PGS does not engage in the exploration for or production of natural gas. Currently, PGS operates a natural gas distribution system that serves approximately 253,000 customers. The system includes approximately 8,100 miles of mains and over 4,800 miles of service lines.
In 1999, the total throughput for PGS was 1.1 billion therms. Of this total throughput, 23 percent was gas purchased and resold to retail customers by PGS, 72 percent was third party supplied gas delivered for retail customers, and 5 percent was gas sold off-system. Industrial and power generation customers consumed approximately 69 percent of PGS' annual therm volume. Commercial customers used approximately 26 percent with the balance consumed by residential customers.
While the residential market represents only a small percentage of total therm volume, residential operations generally comprise 23 percent of total revenues. New residential construction and conversions of existing residences to gas have steadily increased since the late 1980's.
Natural gas has historically been used in many traditional industrial and commercial operations throughout Florida, including production of products such as steel, glass, ceramic tile and food products. Gas climate control technology is expanding throughout Florida, and commercial/industrial customers including schools, hospitals, office complexes and churches are utilizing this new technology.
Within the PGS operating territory, large cogeneration facilities utilize gas technology in the production of electric power and steam. Over the past three years, the company has transported, on average, about 238 million therms annually to facilities involved in cogeneration.
Revenues and therms for PGS for 1999, are as follows:
PGS had 845 employees as of Dec. 31, 1999. A total of 82 employees in six of the company's 13 operating divisions are represented by various union organizations.
REGULATION
The operations of PGS are regulated by the FPSC separate from the regulation of Tampa Electric's electric operations. The FPSC has jurisdiction over rates, service, issuance of certain securities, safety, accounting and depreciation practices and other matters.
In general, the FPSC sets rates at a level that allows a utility such as PGS to collect total revenues (revenue requirements) equal to its cost of providing service, including a reasonable return on invested capital.
The basic costs, other than the costs of purchased gas and interstate pipeline capacity, of providing natural gas service are recovered through base rates. Base rates are designed to recover the costs of owning, operating and maintaining the utility system. The rate of return on rate base, which is intended to approximate PGS' weighted cost of capital, primarily includes its cost for debt, deferred income taxes at a zero cost rate, and an allowed return on common equity. Base prices are determined in FPSC proceedings which occur at irregular intervals at the initiative of PGS, the FPSC or other parties.
PGS recovers the costs it pays for gas supply and interstate transportation for system supply through the Purchased Gas Adjustment (PGA) clause. This charge is designed to recover the costs incurred by PGS for purchased gas, and for holding and using interstate pipeline capacity for the transportation of gas it sells to its customers. These charges are adjusted monthly based on a cap approved annually in an FPSC hearing. The cap is based on estimated costs of purchased gas and pipeline capacity, and estimated customer usage for a specific recovery period, with a true-up adjustment to reflect the variance of actual costs and usage from the projected charges for prior periods. In 1999, PGS received Commission approval to begin recovering costs using different billing factors for residential and commercial customers.
In addition to its base rates and purchased gas adjustment clause charges for system supply customers, PGS customers (except interruptible customers) also pay a per-therm charge for all gas consumed to recover the costs incurred by the company in developing and implementing energy conservation programs, which are mandated by Florida law and approved and supervised by the FPSC. PGS is permitted to recover, on a dollar-for-dollar basis, expenditures made in connection with these programs if it demonstrates that the programs are cost effective for its ratepayers.
In June 1996, following informal workshops held in late 1995, the FPSC initiated a proceeding for the purpose of investigating the unbundling of natural gas services provided by PGS and other local distribution companies subject to the FPSC's regulatory jurisdiction.
In February 2000, the FPSC proposed a rule that would require natural gas utilities to offer transportation-only service to all non-residential customers. PGS believes a generic rule is unnecessary and is opposed to this broad proposal. The rulemaking process is expected to last anywhere from six months to in excess of a year. It is unclear whether the FPSC staff action will lead to FPSC adoption of a rule requiring further unbundling.
Under a separate docket, in June 1999, PGS extended for a two-year period its existing, experimental unbundling program to 2,600 customers from the previous 170 customers. This program, known as the Firm Transportation Aggregation (FTA) program, advances the unbundling initiative being pursued by the FPSC Staff, but contemplates a more reasonable pace toward total unbundled service to non-residential customers. In July, PGS petitioned the FPSC for approval of FTA-2 which contains terms and conditions similar to FTA, except it allows customers new to PGS to transport immediately. Marketers are also allowed to convert existing sales service customers to transportation under FTA-2 equal to the amount of "new" load served by the marketers. The FTA-2 went into effect in October 1999, but a hearing is scheduled for early 2000 to address issues raised by the FPSC staff. Under the unbundling activities currently underway and those that have FPSC approval pending, PGS would continue to receive its base rate for distribution regardless of whether a customer decided to opt for transportation only service or to continue bundled service. It is therefore, not expected that unbundling will have a material adverse effect on PGS' earnings in the future.
In addition to economic regulation, PGS is subject to the FPSC's safety jurisdiction, pursuant to which the FPSC regulates the construction, operation and maintenance of PGS' distribution system. In general, the FPSC has implemented this by adopting the Minimum Federal Safety Standards and reporting requirements for pipeline facilities and transportation of gas prescribed by the U.S. Department of Transportation in Parts 191, 192 and 199, Title 49, Code of Federal Regulations.
PGS is also subject to Federal, state and local environmental laws and regulations pertaining to air and water quality, land use, noise and aesthetics, solid waste and other environmental matters.
COMPETITION
PGS is not in direct competition with any other regulated distributors of natural gas for customers within its service areas. At the present time, the principal form of competition for residential and small commercial customers is from companies providing other sources of energy and energy services including fuel oil, electricity and in some cases liquid propane gas. PGS has taken actions to retain and expand its commodity and transportation business, including managing costs and providing high quality service to customers. The multiple PGA factors approved in 1999 and the FTA-2 program are both designed to improve the competitiveness of natural gas for commercial load.
Competition is most prevalent in the large commercial and industrial markets. In recent years, these classes of customers have been targeted by competing companies seeking to sell gas directly either using PGS facilities or transporting gas through other facilities, thereby bypassing PGS facilities. Many of these competitors are larger natural gas marketers with a national presence. The FPSC has allowed PGS to adjust rates to meet competition for the largest interruptible customers.
GAS SUPPLIES
PGS purchases gas from various suppliers depending on the needs of its customers. The gas is delivered to the PGS distribution system through two interstate pipelines on which PGS has reserved firm transportation capacity for further delivery by PGS to its customers.
Gas is delivered by Florida Gas Transmission Company (FGT) through more than 40 interconnections (gate stations) serving PGS' operating divisions. In addition, PGS' Jacksonville Division receives gas delivered by the South Georgia Natural Gas Company (South Georgia) pipeline through a gate station located northwest of Jacksonville.
Companies with firm pipeline capacity receive priority in scheduling deliveries during times when the pipeline is operating at its maximum capacity. PGS presently holds sufficient firm capacity to permit it to meet the gas requirements of its system commodity customers except during localized emergencies affecting the PGS distribution system, and on abnormally cold days.
Firm transportation rights on an interstate pipeline represent a right to use the amount of the capacity reserved for transportation of gas, on any given day. PGS pays reservation charges on the full amount of the reserved capacity whether or not it actually uses such capacity on any given day. When the capacity is actually used, PGS pays a volumetrically based usage charge for the amount of the capacity actually used. The levels of the reservation and usage charges are regulated by FERC. PGS actively markets any excess capacity available on a day to day basis to partially offset costs recovered through the Purchased Gas Adjustment Clause.
PGS procures natural gas supplies using base load and swing supply contracts distributed among various vendors along with spot market purchases. Pricing generally takes the form of either a variable price based on published indices, or a fixed price for the contract term.
Neither PGS nor any of its interconnected interstate pipelines has storage facilities in Florida. PGS occasionally faces situations when the demands of all of its customers for the delivery of gas cannot be met. In these instances, it is necessary that PGS interrupt or curtail deliveries to its interruptible customers. In general, the largest of PGS' industrial customers are in the categories that are first curtailed in such situations. PGS' tariff and transportation agreements with these customers give PGS the right to divert these customers' gas to other higher priority users during the period of curtailment or interruption. PGS pays these customers for such gas at the price they paid their suppliers (if purchased by the customer under a contract with a term of five years or longer), or at a published index price (if purchased by the customer pursuant to a contract with a term less than five years), and in either case pays the customer for charges incurred for interstate pipeline transportation to the PGS system.
FRANCHISES
PGS holds franchise and other rights with 89 municipalities within its service area. These include the cities of Jacksonville, Daytona Beach, Eustis, Orlando, Lakeland, Tampa, St. Petersburg, Bradenton, Sarasota, Avon Park, Frostproof, Palm Beach Gardens, Pompano Beach, Fort Lauderdale, Hollywood, North Miami, Miami Beach, Miami, Panama City and Ocala. These agreements give PGS a right to operate within the franchise territory. The franchises are irrevocable and are not subject to amendment without the consent of PGS, although in certain events, they are subject to forfeiture.
Municipalities are prohibited from granting any franchise for a term exceeding 30 years. If a franchise is not renewed by a municipality, the franchisee may choose to exercise its statutory right to require the municipalities to purchase any and all property used in connection with the franchise at a valuation to be fixed by arbitration or, if arbitration is unsuccessful, by eminent domain. In addition, several of the municipalities have reserved the right to purchase PGS' property used in the exercise of its franchise, if the franchise is not renewed.
PGS' franchise agreements with the incorporated municipalities within its service area have various expiration dates ranging from March 2000 through December 2029.
In March 2000, the City of Lakeland notified PGS that it intended to begin negotiations to exercise its right to purchase PGS' property consisting of approximately 200 miles of gas line in the Lakeland franchise area when its franchise agreement with PGS expired on March 13, 2000. PGS serves approximately 5,000 customers in Lakeland. The Company continues to negotiate the terms of an extension to the franchise. PGS has continued its discussions with the City of Lakeland urging the city to renew this agreement. While PGS believes it is best suited to serve these customers, it cannot at this time predict the ultimate outcome of these activities. If negotiations prove to be unsuccessful, then a resolution will only be achieved through appropriate legal action.
Franchise fees payable by PGS, which totaled $7.4 million in 1999, are calculated using various formulas which are based principally on natural gas revenues. Franchise fees are collected from only those customers within each franchise area.
Utility operations in areas outside of incorporated municipalities are conducted in each case under one or more permits to use county rights-of-way granted by the county commissioners of such counties. There is no law limiting the time for which such permits may be granted by counties. There are no fixed expiration dates and these rights are, therefore, considered perpetual.
ENVIRONMENTAL MATTERS
PGS's operations are subject to federal, state and local statutes, rules and regulations relating to the discharge of materials into the environment and the protection of the environment generally that require monitoring, permitting and ongoing expenditures. These expenditures have not been significant in the past, but the trend is toward stricter standards, greater regulation and more extensive permitting requirements.
Tampa Electric Company is a potentially responsible party for certain superfund sites and, through its Peoples Gas System division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, Tampa Electric Company estimates its ultimate financial liability at approximately $20 million over the next 10 years. The environmental remediation costs associated with these sites are not expected to have a significant impact on customer prices.
PGS believes that it is in substantial compliance with applicable environmental laws, regulations, orders and rules. It is allowed to recover certain prudently incurred environmental costs through rates charged to its customers.
EXPENDITURES. During the five years ended Dec. 31, 1999, PGS has not incurred any material capital additions to meet environmental requirements, nor are any anticipated for 2000 through 2004.
ITEM 2.
ITEM 2. PROPERTIES.
The company believes that the physical properties are adequate to carry on its business as currently conducted. The properties are generally subject to liens securing long-term debt.
ELECTRIC PROPERTIES
At Dec. 31, 1999, Tampa Electric had five electric generating plants and four combustion turbine units in service with a total net winter generating capability of 3,569 megawatts, including Big Bend (1,742-MW capability from four coal units), Gannon (1,160-MW capability from six coal units), Hookers Point (189-MW capability from five oil units), Phillips (34-MW capability from two diesel units), Polk (250-MW capability from one integrated gasification combined cycle unit (IGCC)) and four combustion turbine units located at the Big Bend and Gannon stations (194 MWs). The capability indicated represents the demonstrable dependable load carrying abilities of the generating units during winter peak periods as proven under actual operating conditions. Units at Hookers Point went into service from 1948 to 1955, at Gannon from 1957 to 1967, and at Big Bend from 1970 to 1985. The Polk IGCC unit began commercial operation in September 1996. In 1991, Tampa Electric purchased two power plants (Dinner Lake and Phillips) from the Sebring Utilities Commission (Sebring). Dinner Lake (11-MW capability from one natural gas unit) and Phillips were placed in service by Sebring in 1966 and 1983, respectively. In March 1994, Dinner Lake Station was placed on long-term reserve standby.
Engineering for repowering Gannon Station began in January 2000, and the company anticipates that commercial operation for the first repowered unit will occur by May 1, 2003. The repowering of the additional units is scheduled to be completed by May 1, 2004. When these units are repowered, the station will be renamed the Bayside Power Station. Total station capacity is expected to increase to about 1,475 megawatts.
Tampa Electric owns 221 substations having an aggregate transformer capacity of 16,654,239 KVA. The transmission system consists of approximately 1,196 pole miles of high voltage transmission lines, and the distribution system consists of 6,939 pole miles of overhead lines and 2,838 trench miles of underground lines. As of Dec. 31, 1999, there were 576,803 meters in service. All of this property is located in Florida.
All plants and important fixed assets are held in fee except that title to some of the properties is subject to easements, leases, contracts, covenants and similar encumbrances and minor defects, of a nature common to properties of the size and character of those of Tampa Electric.
Tampa Electric has easements for rights-of-way adequate for the maintenance and operation of its electrical transmission and distribution lines that are not constructed upon public highways, roads and streets. It has the power of eminent domain under Florida law for the acquisition of any such rights-of-way for the operation of transmission and distribution lines. Transmission and distribution lines located in public ways are maintained under franchises or permits.
Tampa Electric has a long-term lease for its office building in downtown Tampa which serves as headquarters for TECO Energy, Tampa Electric and numerous other TECO Energy subsidiaries.
GAS PROPERTIES
PGS' distribution system extends throughout the areas it serves in Florida, and consists of approximately 12,900 miles of pipe, including approximately 8,100 miles of mains and over 4,800 miles of service lines.
PGS operating divisions are located in thirteen markets throughout Florida. While most of the operations, storage and administrative facilities are owned, a small number are leased.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
On Nov. 3, 1999, a civil action was filed by the U.S. Department of Justice on behalf of the U.S. Environmental Protection Agency against Tampa Electric Company in the United States District Court for the Middle District of Florida, and EPA issued a Notice of Violation (NOV) for violations under the Florida State Implementation Plan (SIP). Both enforcement actions alleged that Tampa Electric made modifications to its Big Bend and Gannon generating plants without obtaining permits and installing the best available pollution control equipment as required by the Prevention of Significant Deterioration provisions of the Clean Air Act and the requirements of the SIP.
On Feb. 29, 2000, Tampa Electric Company, the U.S. Environmental Protection Agency and the U.S. Department of Justice announced they had resolved the federal agencies' pending enforcement actions (including the NOV) filed last year against Tampa Electric. The resolution, which was in the form of a consent decree, resulted in full and final settlement of the November 1999 federal litigation and NOV alleging violations of the New Source Review (NSR) requirements of the Clear Air Act. The Consent Decree was lodged with the U.S. District Court for the Middle District of Florida in Tampa, Florida, and is subject to a 30-day public comment period, before it may be entered by the Court at which time it will become effective. See the discussion under TAMPA ELECTRIC--ELECTRIC OPERATIONS - ENVIRONMENTAL MATTERS.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
All of the company's common stock is owned by TECO Energy, Inc. and therefore, there is no market for the stock.
The company pays dividends substantially equal to its net income applicable to common stock to TECO Energy. Such dividends totaled $149.5 million in 1999 and $147.5 million for 1998. See Note C on page 31 for a description of restrictions on dividends on the company's common stock.
ITEM 7.
ITEM 7. MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS.
THE MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS WHICH FOLLOWS CONTAINS FORWARD-LOOKING STATEMENTS WHICH ARE SUBJECT TO THE INHERENT UNCERTAINTIES IN PREDICTING FUTURE RESULTS AND CONDITIONS. CERTAIN FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE PROJECTED IN THESE FORWARD-LOOKING STATEMENTS INCLUDE THE FOLLOWING: GENERAL ECONOMIC CONDITIONS, PARTICULARLY THOSE IN TAMPA ELECTRIC COMPANY'S SERVICE AREAS AFFECTING ENERGY SALES; WEATHER VARIATIONS AFFECTING ENERGY SALES AND OPERATING COSTS; POTENTIAL COMPETITIVE CHANGES IN THE ELECTRIC AND GAS INDUSTRIES, PARTICULARLY IN THE AREA OF RETAIL COMPETITION; REGULATORY ACTIONS; COMMODITY PRICE CHANGES AFFECTING THE COMPETITIVE POSITIONS OF BOTH TAMPA ELECTRIC AND PEOPLES GAS SYSTEM; AND CHANGES IN AND COMPLIANCE WITH ENVIRONMENTAL REGULATIONS THAT MAY IMPOSE ADDITIONAL COSTS OR CURTAIL SOME ACTIVITIES. THESE FACTORS ARE DISCUSSED MORE FULLY UNDER "INVESTMENT CONSIDERATIONS" IN TECO ENERGY INC.'S ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DEC. 31, 1999, AND REFERENCE IS MADE THERETO.
EARNINGS SUMMARY:
The acquisitions of Peoples Gas System, Inc. and West Florida Natural Gas Company in June 1997, were accounted for as poolings of interests and, accordingly, the 1997 financial and operating data include the results of Peoples Gas System, Inc. And West Florida Natural Gas Company, combined for the full year. However, prior year financial statements have not been restated to reflect the results of West Florida Natural Gas Company due to its size.
Net income for 1999 of $144.9 million declined 1 percent from the prior year results of $146.4 million due primarily to the impact of previously deferred revenues and certain charges described in the CHARGES TO EARNINGS section below. Net income in 1998 also declined 1 percent from 1997's results primarily as a result of the charges described in the CHARGES TO EARNINGS section below. For a description of the origination and treatment of deferred revenues, see UTILITY REGULATION - RATE STABILIZATION STRATEGY section.
Operating income, excluding charges described in the CHARGES TO EARNINGS section, declined 1.6 percent in 1999 reflecting the impact of deferred revenue changes. Operating income in 1999 reflected the reversal of $11.9 million of previously deferred electric revenues compared to the recognition of $38.3 million of previously deferred electric revenues in 1998. Operating income in 1997 reflected the recognition of $30.5 million of previously deferred electric revenues and the inclusion of Polk Unit One in rate base for earnings purposes. See UTILITY REGULATION - RATE STABILIZATION STRATEGY section.
Earnings in 1999 and 1998 were affected by certain events and adjustments that were unusual in nature and resulted in charges which are not expected to recur in future periods. These charges are described in the CHARGES TO EARNINGS section on page 12 and from a regulatory ruling denying recovery of coal expenses over an established benchmark for coal purchases from Gatliff since 1992 (described in the TAMPA ELECTRIC - ELECTRIC OPERATING RESULTS section).
Results in 1997 reflected one-time costs from the 1997 Peoples Gas companies merger and an FPSC decision, described in the TAMPA ELECTRIC - ELECTRIC OPERATING RESULTS section, to change the regulatory treatment of two wholesale power sales contracts.
CONTRIBUTIONS BY OPERATING DIVISION
(1) Excludes a pretax credit of $7.9 million. See CHARGES TO EARNINGS section on page 12. (2) Excludes a pretax charge of $9.6 million for treatment of a wholesale contract. See CHARGES TO EARNINGS section on page 12. (3) Deferred revenue benefit recognized under the rgulatory agreement related to the charge for tax settlement described in the CHARGES TO EARNINGS section on page 12. (4) Pre-tax charge for treatment of a wholesale contract, described in the CHARGES TO EARNINGS SECTION ON PAGE 12.
CHARGES TO EARNINGS
In 1999 and 1998 the company recognized certain charges that were unusual and nonrecurring in nature.
1999 CHARGES
The charges in 1999 totaled $18.3 million pretax ($13.7 million after tax) and consisted of the following:
Tampa Electric recorded a charge of $10.5 million ($6.4 million after tax) based on FPSC audits of its 1997 and 1998 earnings, which among other things, limited its regulatory equity ratio to 58.7 percent, a decrease of 91 basis points and 224 basis points from 1997's and 1998's ratios, respectively.
Tampa Electric also recorded a charge of $3.5 million after tax, representing management's estimate of additional expense to resolve the litigation filed by the United States Environmental Protection Agency.
A net after-tax charge, after recovery under the then current regulatory agreement totaling $3.8 million was also recognized reflecting corporate income tax provisions and settlements related to prior years' tax returns.
1998 CHARGES
In 1998, Tampa Electric recognized charges totaling $16.9 million, pretax ($10.3 million, after tax). These charges consisted of the following:
The FPSC in September 1997 ruled that under the regulatory agreements effective through 1999 the costs associated with two long-term wholesale power sales contracts should be assigned to the wholesale jurisdiction and that for retail rate making purposes the costs transferred from retail to wholesale should reflect average costs rather than the lower incremental costs on which the two contracts are based. As a result of this decision and the related reduction of the retail rate base upon which Tampa Electric is allowed to earn a return, these contracts became uneconomic. One contract was terminated in 1997. As to the other contract, which expires in March 2001, Tampa Electric entered into firm power purchase contracts with third parties to provide replacement power through 1999 and is no longer separating the associated generation assets from the retail jurisdiction. The cost of purchased power under these contracts exceeded the revenues expected through 1999. To reflect this difference, Tampa Electric recorded a $9.6 million charge ($5.9 million after tax) in 1998. In November 1999, the FPSC approved a company-proposed treatment for the remaining 14 1/2 months of the contract that flows 100 percent of the revenues from the contract back to retail customers.
Tampa Electric also recorded a charge of $7.3 million ($4.4 million after tax) in other expense for an FPSC decision in 1998 denying recovery of certain BTU coal quality price adjustments for coal purchases from TECO Coal since 1993.
OPERATING RESULTS
TAMPA ELECTRIC - ELECTRIC OPERATIONS
TAMPA ELECTRIC OPERATING RESULTS
Tampa Electric's 1999 operating income, before charges described in the CHARGES TO EARNINGS section, decreased 4 percent from 1998. Results in 1999 included the deferral of $11.9 million of revenues excluding an offsetting nonrecurring pretax benefit of $7.9 million of deferred revenues recognized under the then current regulatory agreement related to the charge for tax settlements. 1998's results reflected the recognition of $38.3 million of previously deferred revenues partially offset by a $20.8 million temporary base rate reduction. Favorably impacting 1999, customer growth was 2.5 percent and operations and maintenance expenses were $9.6 million lower, primarily the result of efficiency improvements in 1999. Expenses were higher in 1998, primarily to enhance system reliability.
(1) Includes $11.9 million of deferred revenues. This amount is before the $7.9 million deferred revenue benefit recognized under the regulatory agreement related to the charge for tax settlements, described in the CHARGES TO EARNINGS section. (2) Includes the recognition of previously deferred revenues totaling $38.3 million offset by temporary base rate reductions of $20.8 million, described in the UTILITY REGULATION - RATE STABILIZATION STRATEGY section. (3) Includes the recognition of previously deferred revenues totaling $30.5 million offset by temporary base rate reductions of $4.6 million, described in the UTILITY REGULATION - RATE STABILIZATION STRATEGY section. (4) Excludes a pretax charge of $9.6 million for treatment of a wholesale contract, described in the CHARGES TO EARNINGS section.
TAMPA ELECTRIC OPERATING REVENUES
The economy in Tampa Electric's service area continued to grow in 1999, with increased employment from corporate relocations and expansions. The Tampa metropolitan area's employment grew over 5 percent in 1999, placing it among the top five in the U.S. for job growth.
Tampa Electric's 1999 operating revenues decreased 3 percent, primarily because the company deferred revenues in 1999, while in 1998 it benefitted from the recognition of revenues deferred in prior years. The company experienced customer growth of 2.5 percent while retail energy sales were 1.4 percent lower. Tampa Electric's 1998 revenues, including recognition of $38.3 million of previously deferred revenues partially offset by a $20.8 million temporary base rate reduction, increased almost 4 percent, with customer growth increasing 2.3 percent and retail energy sales up 6.2 percent.
Overall, the company experienced a higher-margin customer mix in 1999, primarily the result of retail customer growth of 2.5 percent and strong commercial sales. Total retail energy sales were lower primarily due to a slowdown in the phosphate industry, the lowest margin sector.
Combined residential and commercial energy sales increased slightly in 1999, as the addition of almost 13,000 new customers more than offset the effects of mild weather. These sales increased over 7 percent in 1998, reflecting the addition of almost 12,000 customers and increased demand during warmer-than-normal summer weather.
Non-phosphate industrial sales increased in 1999 and 1998, reflecting the shift of some commercial customers to the industrial classification to take advantage of favorable tax law changes on electricity used in manufacturing. This shift does not affect Tampa Electric revenues.
Sales to the phosphate industry declined in 1999 and in 1998. The phosphate industry has experienced a slowdown over the past two years. Several mines were shut down in late 1998, and additional closures were announced in 1999. The phosphate industry is currently experiencing lower pricing and oversupply. According to phosphate industry sources, the market is expected to remain in this downturn for the next two years and to rebound in 2002. Revenues from phosphate sales represented slightly less than 3 percent of base revenues in 1999 and in 1998.
Based on expected growth reflecting population increases and business expansion, Tampa Electric projects retail energy sales growth of approximately 2.5 percent annually over the next five years, with combined energy sales growth in the residential and commercial sectors of almost 3 percent annually. Energy sales to non-phosphate industrial customers are expected to grow almost 2 percent annually over the next five years.
These growth projections assume continued local area economic growth, normal weather and certain other factors.
Non-fuel revenues from sales to other utilities were $37 million in 1999, $36 million in 1998 and $39 million in 1997. Megawatt hours sold to other utilities decreased in 1999 primarily because of mild weather and lower Tampa Electric generating unit availability. The slight increase in non-fuel revenues in 1999 was the result of increased partial-requirement sales due to contractual escalations in megawatt requirements.
TAMPA ELECTRIC OPERATING EXPENSES
Overall expenses were down 3 percent in 1999, reflecting lower fuel consumption and lower operations and maintenance expense. Partially offsetting these reductions were property tax settlements and environmental study costs associated with the state environmental settlement described below and in the ENVIRONMENTAL COMPLIANCE section.
Non-fuel operations and maintenance expenses decreased 4 percent in 1999, the result of effective cost management and improved efficiency throughout the company. Required expenditures to enhance system reliability and timing of generation station outages contributed to the higher maintenance costs in 1998.
Tampa Electric's 250-megawatt, state-of-the-art, clean-coal technology Polk Unit One was placed into service in late 1996. Between 1996 and 1999, a total of approximately $29 million was received from the U.S. Department of Energy (DOE) to partially offset the unit's non-fuel operations and maintenance expenses. 1999 was the last year in which Tampa Electric was eligible to receive DOE funding for Polk Unit One.
Non-fuel operations and maintenance expenses in 2000 are expected to be higher than in 1999, reflecting the discontinuance of DOE funding of $6 to 7 million and operating expenses estimated at $4 to 5 million associated with the new Big Bend flue-gas
desulfurization (FGD) system, described in the ENVIRONMENTAL COMPLIANCE section. Following 2000, expenses are expected to increase at or below the rate of inflation over the next several years.
Reflecting normal plant additions to serve the growing customer base, depreciation expense increased 1 percent in 1999 and 3.3 percent in 1998. Depreciation expense is projected to rise significantly for the next several years due to the addition of a FGD system in 2000 and expected additional depreciation of certain assets related to the Gannon repowering project. See the ENVIRONMENTAL COMPLIANCE section.
Taxes other than income increased in 1999 as a result of higher property taxes due to the settlement of prior year tax issues with Polk County. This settlement clarified issues mainly related to Polk Unit One for 1997, 1998 and beyond in a manner satisfactory to the company. Taxes other than income increased in 1998 as a result of higher gross receipts taxes and franchise fees related to higher energy sales. The sales-related taxes are recovered through customer bills.
Fuel expense decreased in 1999 from 1998 due to lower energy sales and a higher reliance on purchased power attributable to lower unit availability. Average coal costs, on a cents-per-million BTU basis, increased slightly in 1999 and 1 percent in 1998. In 1998, the FPSC disallowed, retroactively to the beginning of 1993, certain quality adjustments for coal purchased from a Tampa Electric affiliate, resulting in a pretax charge of $7.3 million.
Purchased power increased in 1999 due to lower unit availability, the provision of replacement power for certain wholesale power sales contracts and an explosion at the Gannon plant in April. In 1998, purchased power increased primarily due to weather-related demand. In each year, substantially all fuel and purchased power expenses were recovered through the fuel adjustment clause.
Nearly all of Tampa Electric's generation in the last three years has been from coal, and the fuel mix is expected to continue to be substantially comprised of coal until 2003 when the first of three repowered units is scheduled to begin operating on natural gas. See the ENVIRONMENTAL COMPLIANCE section.
External forecasts indicate relatively stable coal prices for the next few years. On a total energy supply basis, company-generation accounted for 88 percent of the total system energy requirement in 1999, compared with 92 percent in 1998.
On April 8, 1999, an explosion at Tampa Electric's Gannon Station Unit Six, a 375-megawatt generator that was off line for scheduled spring maintenance, resulted in damage to the unit, the temporary shut down of the other five units at the Station and injuries to 45 employees and contractors, including three fatalities. The units at Gannon Station that were affected by the accident were returned to service in the second and third quarter. The cost of replacement fuel and purchased power totaled $5 million; $1.8 million was approved by the FPSC for recovery through Tampa Electric's fuel and purchased power clause with little impact on customer rates, and the balance was recovered from interruptible customers. The costs resulting from the accident were substantially covered by insurance. The impact on current-year operation and maintenance expenses was approximately $2 million. The U.S. Occupational Safety and Health Administration (OSHA) concluded its safety investigation at the Gannon Station. OSHA found no willful violations, and Tampa Electric agreed not to contest OSHA's citations. Tampa Electric paid $30,075 in fines to OSHA largely related to the explosion at the Gannon plant. This amount included a reduction of 10 percent due to the company's excellent safety history.
PEOPLES GAS SYSTEM
PEOPLES GAS SYSTEM RESULTS
Peoples Gas System (PGS) achieved operating income growth of 18 percent in 1999, with the increase due primarily to new customer additions from system expansion and lower operating expenses resulting from management's decision to discontinue the appliance sales and service business in mid-1998. The benefits of customer growth for the year were partially offset by the less favorable weather patterns during 1999.
Operating income grew 5 percent in 1998, from new customer additions and higher average utilization per customer. The benefits of customer growth for the year were partially offset by the effects of warmer-than-normal weather during the winter months and by restructuring costs associated with management's decision to exit the appliance sales and service business.
The actual cost of gas and upstream transportation purchased and resold to end-use customers is recovered through a Purchased Gas Adjustment (PGA) clause approved by the FPSC.
Residential therm sales decreased slightly in 1999, the result of less favorable weather patterns in the first quarter offset in part by new customer additions. Therm sales to commercial customers increased in 1999, reflecting a growing number of higher-margin customers.
Operating revenues from residential customers increased 2 percent in 1999. Revenue from commercial customers decreased 9 percent, while revenues from industrial and power generation customers were up approximately 33 percent.
The increase in operating revenues in the residential segment reflects higher revenue from monthly customer charges, the result of strong residential customer growth in 1999.
The decline in operating revenues from the commercial segment reflects a shift from commodity sales to transportation sales for a growing number of commercial customers. For commodity sales, the cost-of-gas pass-through is included in operating revenues; for transportation customers, there is no cost-of-gas pass-through. Therefore, the net financial impact to the company is the same for both groups.
Operating expenses excluding federal and state income taxes decreased in 1999, reflecting cost savings associated with management's decision in mid-1998 to exit the appliance sales and service business.
PGS expects to invest an average of $50 to $60 million per year for the next five years to grow the business. Infrastructure is being expanded both in areas currently served and in areas not yet served by natural gas.
In 1998, PGS announced plans to expand into the Southwest Florida market providing service to Fort Myers, Naples, Cape Coral and surrounding areas. In 1999, the company began connecting customers and delivering gas to North Fort Myers and expects to complete the long-haul portion of this extension of its distribution system by the end of the first quarter of 2000. External sources anticipate that more than 100,000 new homes and businesses will be added in this market over the next decade, representing a significant opportunity for growth in the high-end residential and the commercial customer sectors.
The company also has expanded service to the U.S. Naval Station at Mayport near Jacksonville and anticipates that the Mayport facilities and surrounding communities will use over 2.6 million therms of natural gas annually. In addition, PGS will construct 19 miles of pipeline in 2000 to connect Jacksonville Electric Authority's planned combustion turbine generating units.
PGS expects increases in sales volumes and corresponding revenues in 2000, and continued customer additions and related revenues reflecting the Southwest Florida expansion and other expansion efforts throughout the state.
These growth projections assume continued local area economic growth, normal weather and other factors.
PGS is the largest investor-owned gas distribution utility in Florida, with about 70 percent of the investor owned local distribution company market. It serves approximately 250,000 customers in all of the major metropolitan areas of Florida.
YEAR 2000 COMPUTER SYSTEMS PREPARATION
Tampa Electric has encountered no significant problems related to the Year 2000 issue and all computer systems are performing as expected to date.
The total cost of Year 2000 remediation for Tampa Electric Company was approximately $9 million, which included contracted resources, purchases and internal labor. A breakdown of project costs is as follows: Tampa Electric - $6.5 million, and Peoples Gas System - $2.5 million. Approximately 40 percent of these costs were attributable to testing expenses, and the remainder consisted primarily of renovation or replacement costs. The company does not anticipate any significant additional costs related to this issue.
NON-OPERATING ITEMS
OTHER INCOME (EXPENSE)
Other income (expense) in 1999 included charges of $3.5 million to provide for Tampa Electric's expected costs of settling an EPA lawsuit and $10.0 million for a regulatory decision limiting the utility's regulatory equity ratio to 58.7 percent for 1997 and 1998.
Other income (expense) in 1998 included a charge of $7.3 million at Tampa Electric reflecting an FPSC decision denying recovery of certain coal expenses from an affiliate. These 1999 and 1998 charges are described in the CHARGES TO EARNINGS section.
Allowance for other funds used during construction (AFUDC) was $1.3 million in 1999 and $.1 million in 1997; no AFUDC was recorded in 1998. AFUDC is expected to increase over the next several years reflecting Tampa Electric's generation expansion activities.
INTEREST CHARGES
Interest charges were $77.4 million compared to $63.4 million in 1998. A charge for income tax settlements and provisions, discussed in the CHARGES TO EARNINGS section, included $12.7 million of interest expense and accounted for much of the increase over 1998. Higher borrowing levels associated with new investments in the operating businesses also increased interest expense.
Interest charges were down slightly in 1998, reflecting lower interest on a declining deferred revenue balance at Tampa Electric and lower short-term rates, partially offset by higher borrowing levels for new business initiatives.
ENVIRONMENTAL COMPLIANCE
Tampa Electric met the environmental compliance requirements for the Phase I emission limitations imposed by the Clean Air Act Amendments (CAAA) which became effective Jan. 1, 1995 by using blends of lower-sulfur coal, integrating the Big Bend Unit Four FGD system with Unit Three, implementing operational modifications and purchasing emission allowances. For Phase II, which began Jan. 1, 2000, further reductions in sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions were required. To comply with the Phase II SO2 requirements, the company installed a new FGD system at Big Bend Units One and Two and will rely less on fuel blending and SO2 allowance purchases. The $83 million scrubber was placed in service on Dec. 30, 1999 and will significantly reduce the amount of SO2 emitted by Tampa Electric's Big Bend Units One and Two. As a result of this project, all of the units at Big Bend Station, Tampa Electric's largest generating station, are equipped with FGD, or scrubber technology. The FPSC approved recovery of the costs associated with the Big Bend Units One and Two FGD system in November 1999 and cost recovery began in January 2000. In order to comply with the Phase II NOx emission limits on a system wide average, Tampa Electric has implemented combustion optimization projects at Big Bend and Gannon Stations.
In 1997, the EPA began an investigation under the Clean Air Act (CAA) of coal-fired electric power generators to determine compliance with New Source Review (NSR) environmental permitting requirements associated with repairs, maintenance, modifications and operational changes made to the facilities over the years. The EPA asserted that certain electric utilities, including Tampa Electric, should have applied for pre-construction permits for certain unit maintenance projects, and that the permitting review of such projects would have included NSR, resulting in requirements that the units meet more restrictive, Best Available Control Technology (BACT) standards for NOx, SO2 and particulate matter (PM). Tampa Electric disagreed with EPA's interpretation of its NSR rules and its definitions of what constitutes maintenance. On Nov. 3, 1999, despite Tampa Electric's extensive efforts to reach a mutually agreeable settlement with the EPA, the Department of Justice sued Tampa Electric and six other electric utilities and issued an administrative order against TVA on behalf of the EPA for alleged violations of the CAA associated with this NSR issue. Coincident with the lawsuits, EPA issued Notices of Violations (NOV) alleging similar NSR violations under the relevant State Implementation Plans (SIP).
Following notice to the State of Florida of the EPA's NOV, the Florida Department of Environmental Protection (DEP), the agency responsible for enforcement of the Air Quality SIP, began negotiations to resolve the same allegations under the SIP that Tampa Electric had not applied for appropriate permits for certain unit maintenance projects at Gannon and Big Bend Stations and, therefore, had operated the coal-fired units without BACT for NOx and SO2. Effective Dec. 16, 1999, a Consent Final Judgment
(CFJ) entered into between DEP and Tampa Electric resolved the DEP claims. The requirements of the CFJ require the implementation of several environmental initiatives which include repowering certain Gannon Station units with natural gas and placing the remaining Gannon units on reserve standby by the end of 2004. It also requires Tampa Electric to implement other specific initiatives to further reduce NOx, SO2 and PM emissions at Big Bend Station Unit Four by 2007 and Big Bend Units One, Two and Three by 2010.
On Feb. 29, 2000, Tampa Electric Company, the U.S. Environmental Protection Agency and the U.S. Department of Justice announced they had resolved the federal agencies' pending enforcement actions (including the NOV) filed last year against the company. The resolution, which was in the form of a consent decree, resulted in full and final settlement of the November 1999 federal litigation and NOV alleging violations of NSR requirements of the Clear Air Act. The consent decree was lodged with the U.S. District Court for the Middle District of Florida in Tampa, Florida, and is subject to a 30-day public comment period before it may be entered by the Court at which time it will become effective.
The agreement is substantially the same as Tampa Electric's earlier agreement with the Florida Department of Environmental Protection with respect to environmental controls and pollution reductions reached on Dec. 7, 1999; however, it contains specific detail with respect to the availability of the scrubbers and earlier incremental NOx reduction efforts on Big Bend Units One, Two and Three. In order to eliminate the uncertainties of litigation and in exchange for a release from past liability and a safe harbor during the 10-year term of the consent decree, the Company agreed to pay a $3.5 million civil penalty. Under the consent decree, Tampa Electric will commit to a comprehensive cleanup program that will dramatically decrease emissions from the company's power plants. The agreement makes Tampa Electric the first utility in the nation to respond to EPA's coal-fired utility initiative.
Engineering for the repowering project began in January 2000, and the company anticipates that commercial operation for the first repowered unit occur by May 1, 2003. The repowering of additional units is scheduled to be completed by May 1, 2004. When these units are repowered, the station will be renamed the Bayside Power Station and will have an increased total station capacity of about 1,475 megawatts of natural gas-fueled electric energy.
Tampa Electric Company is a potentially responsible party for certain superfund sites and, through its Peoples Gas System division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, Tampa Electric Company estimates its ultimate financial liability at approximately $20 million over the next 10 years. The environmental remediation costs associated with these sites are not expected to have a significant impact on customer prices.
UTILITY REGULATION
RATE STABILIZATION STRATEGY
Tampa Electric's objectives of stabilizing prices through 1999 and securing fair earnings opportunities during this period were accomplished through agreements entered into in 1996 with the Florida Office of Public Counsel (OPC) and the Florida Industrial Power Users Group (FIPUG) which were approved by the FPSC.
Prior to these agreements, the FPSC approved a plan submitted by Tampa Electric to defer certain 1995 revenues. Under this plan Tampa Electric's allowed return on equity (ROE) was established at an 11.75 percent midpoint with a range of 10.75 percent to 12.75 percent. For 1995 an initial $15 million of revenues were deferred as well as 50 percent of actual revenues in excess of a ROE of 11.75 percent up to a net earned ROE of 12.75 percent. Also as part of this plan, Tampa Electric's oil backout tariff was eliminated as of January 1996, reducing annual revenues by approximately $12 million.
In 1995, Tampa Electric deferred $51 million of revenues under this plan. The deferred revenues accrued interest at the 30-day commercial paper rate as specified in the Florida Administrative Code.
In 1996, the FPSC approved agreements between Tampa Electric, the OPC and the FIPUG which froze base rates for the electric utility through 1999, returned $50 million to customers between October 1996 and December 1998 through refunds and a temporary base rate reduction and allowed full recovery of the capital costs incurred for the Polk Unit One project.
In addition, the agreements set forth multi-year plans for allocating revenues based on Tampa Electric's ROE. For the years 1996 through 1998, Tampa Electric retained all revenues contributing to an ROE up to 11.75 percent. Under this plan, any additional revenues were allocated as follows:
In 1996, 40 percent of any actual revenues contributing to an ROE in excess of 11.75 percent were included in 1996 revenues. The remaining 60 percent were deferred for recognition in 1997 and 1998. The company deferred $34 million in 1996. This amount and the deferred revenues and interest from 1995 (less $25 million of refunds) provided $68 million for recognition by the company in 1997 and 1998.
In 1997, 40 percent of any revenues that contributed to an ROE in excess of 11.75 percent up to 12.75 percent were included in revenues. The remaining 60 percent were deferred for use in 1998, as were all revenues in excess of 12.75 percent. The company recognized $31 million in 1997 of the revenues and interest deferred from 1995 and 1996.
In 1998, 40 percent of any actual revenues contributing to a ROE in excess of 11.75 percent up to 12.75 percent were included in revenues. The remaining 60 percent, as well as revenues in excess of 12.75 percent were deferred for anticipated refund to customers pending resolution of the FIPUG protest of the FPSC decision as discussed below. The company recognized $38 million in 1998 of the revenues and interest deferred from prior years.
For 1999, 60 percent of the revenues contributing to an ROE in excess of 12 percent were deferred for refund to customers in 2000 following final review by the FPSC. Tampa Electric's 1999 results reflect an anticipated refund to customers of $4.0 million earned above the 12 percent.
In 1999, the FPSC reviewed Tampa Electric's earnings for 1997 and 1998 and ordered that $11.2 million plus interest be refunded to customers in 2000. In November 1999, FIPUG protested the FPSC decisions for both years and requested a hearing to review a wide range of costs incurred by the company over the two-year period. The FPSC ordered that the $11.2 million refund be withheld with interest until the protest is heard and resolved. A hearing is scheduled for August 2000.
The regulatory arrangements described above covered periods that ended on Dec. 31, 1999. Tampa Electric's rates and its 11.75 percent allowed rate of return on common equity midpoint will continue in effect until such time as changes are occasioned by an agreement approved by the FPSC or other FPSC action as a result of rate or other proceedings initiated by Tampa Electric, FPSC staff or other interested parties. Tampa Electric believes that its currently allowed ROE range is reasonable based on the current interest rate environment and previous FPSC rulings.
COST RECOVERY CLAUSES
In October 1999, Tampa Electric filed with the FPSC for approval of fuel, capacity, environmental and conservation cost recovery clause rates for the period January 2000 through December 2000. On Nov. 22 and 23, 1999, the FPSC held hearings and: 1) approved the company's proposed replacement fuel and purchased power costs associated with the Gannon Unit Six explosion; 2) approved the company's proposed regulatory treatment for the remaining terms of a wholesale power sales agreement for Jan. 1, 2000 through March 15, 2001; 3) approved cost recovery of purchased power agreements entered into for 1999 and 2000 for enhanced system reliability including a 12-year agreement entered into with Hardee Power Partners; 4) approved the recovery of capital and operating and maintenance costs for the Big Bend Units One and Two FGD system; and 5) approved a fair accounting treatment for retired environmental assets that are being replaced by new technology environmental assets. Including these changes, the total residential bill for 1,000 kwh in 2000 will be $81.78, which represents a $1.90, or 2 percent increase over 1999 rates.
LONG RANGE POWER SUPPLY PLANNING
Tampa Electric filed a 10-year site plan with the FPSC in April 1999. Since that time, several events have occurred that have caused Tampa Electric to make several modifications to its plan. First, as part of the FPSC's assessment of Florida's electric reliability for future years, the FPSC ordered a generic investigation into the aggregate reserve margins planned for peninsular Florida. The investigation was to include an evaluation of the manner in which reserve margins are calculated, the level of reserve margins considered adequate for Florida's utilities, and the remedial action that would be taken to assure adequate reserve margins. Prior to a formal, evidentiary hearing scheduled to be held in November 1999, Tampa Electric along with Florida Power & Light and Florida Power Corp. submitted a proposed stipulation to the FPSC to voluntarily adopt a minimum 20 percent reserve margin planning criteria from then current 15 percent criteria for the resolution of the issues in the investigation. The Florida investor-owned utilities (IOUs) proposed to implement the 20 percent criterion over a transition period of four years. In December 1999 the FPSC approved the proposed stipulation. In addition, the FPSC ordered its staff to conduct workshops to address reliability issues related to non-firm electric resources that were identified in the original reserve margin proceeding. These workshops are scheduled for the first quarter of 2000.
Subsequent to the approval of the stipulation, Tampa Electric filed a modification to its planning reserve margin criteria to include a minimum 7 percent summer supply-side component (firm resources) to the overall 20 percent reserve margin planning criteria. A supply-side reserve margin standard establishes a balance of resources by requiring a minimum level of supply-side reserves while not limiting the contributions of non-firm load resources.
Another change to the 10-year site plan was that Tampa Electric accelerated the in-service date of its next two 180 megawatt combustion turbines from January 2001 to September 2000 and from January 2003 to May 2002. Finally the company entered into a 12-year purchased power agreement with Hardee Power Partners. Tampa Electric's original purchased power agreement with Hardee Power Partners, entered into in 1989, provided the company the option of building out the existing site by installing a 75 megawatt combustion turbine that is expected to be in service by May 15, 2000. Through all of these actions, Tampa Electric expects enhanced system reliability for the benefit of all its customers.
UTILITY COMPETITION: ELECTRIC
Tampa Electric's retail electric business is substantially free from direct competition with other electric utilities, municipalities and public agencies. At the present time, the principal form of competition at the retail level consists of self-generation available to larger users of electric energy. Such users may seek to expand their options through various initiatives, including legislative and/or regulatory changes that would permit competition at the retail level. Tampa Electric intends to take all appropriate actions to retain and expand its retail business, including managing costs and providing high-quality service to retail customers.
In December, the Federal Energy Regulatory Commission (FERC) issued its rule on regional transmission organizations (RTOs). This rule is driven by the FERC's continuing effort to effect open access to transmission facilities in large, regional markets. The rule provides guidelines to utilities for joining RTOs by December 2001. These guidelines specify minimum characteristics and functions.
In response to the FERC activity in this area, the FPSC has been holding workshops since January 1999 to discuss transmission issues within peninsular Florida. Although the IOUs, municipals, cooperatives and marketers participating in the workshops do not yet agree on how to resolve specific issues related to planning, operations, pricing and governance, they and the FPSC agree that a national one-size-fits-all approach is not appropriate. With the encouragement of the FPSC, Tampa Electric is working with utilities in the state and others to develop a peninsular Florida solution. These activities have been recently accelerated by Florida Power Corp. and Carolina Power and Light, recognizing that some type of RTO proposal is an integral feature for FERC approval of their proposed merger.
WHOLESALE POWER MARKET
There is presently active competition in the wholesale power markets in Florida, increasing largely as a result of the Energy Policy Act of 1992 and related federal initiatives. This act removed certain regulatory barriers for independent power producers and required utilities to transmit power from such producers, utilities and others to wholesale customers.
In 1999, the city of New Smyrna Beach and an affiliate of Duke Energy Corporation applied for an FPSC determination of need for a proposed 514-megawatt merchant power plant in Volusia County, Florida, to supply 30 megawatts of capacity and associated energy to the Utilities Commission of the City of New Smyrna Beach with the remaining capacity to be used on a speculative basis. Tampa Electric and others intervened to oppose this proposal. Tampa Electric believes that only Florida utilities or entities with contracts for firm capacity and an obligation to serve the long-term needs of a Florida utility can legally be applicants under the Florida Power Plant Siting Act (PPSA). The PPSA sets the state electric energy/environmental policy and governs the building of new generation involving steam capacity of 75 megawatts or more. It requires the applicant to demonstrate that a plant is needed prior to receiving construction and operating permits. On March 4, 1999, the FPSC determined that the proponents of the merchant plant were proper applicants under the PPSA and voted to approve the need for the proposed merchant plant. This decision has been appealed by the Florida IOUs and the Florida Supreme Court heard oral arguments on Feb, 19, 2000. A decision on the appeal is not expected until April 2000 or later.
Following Duke/New Smyrna Beach, several companies have proposed merchant plant projects in Florida. In September 1999, the Okeechobee Generating Company, a subsidiary of Pacific Gas and Electric, filed for a determination of need for two combined cycle units that would generate approximately 550 megawatts. In addition several other merchant plants have been proposed to be constructed in Florida that do not fall under the requirements to file a determination of need due to the fact that the proposed generation involves steam capacity less than 75 megawatts.
If the FPSC's decision to allow the Duke plant to operate is upheld or other regulatory or legislative actions are taken that would allow the construction of wholesale merchant power plants, the wholesale operations of Tampa Electric and other Florida utilities could be adversely affected.
UTILITY COMPETITION: GAS
Although Peoples Gas System is not in direct competition with any other regulated distributors of natural gas for customers within its service areas, there are other forms of competition. At the present time, the principal form of competition for residential and small commercial customers is from companies providing other sources of energy, including electricity.
Competition is most prevalent in the large commercial and industrial markets. In recent years, these classes of customers have been targeted by companies seeking to sell gas directly, either using Peoples Gas System facilities or transporting gas through other facilities, thereby bypassing Peoples Gas System facilities. In response to this competition, various programs have been developed including the provision of transportation services at discounted rates.
In general, Peoples Gas System faces competition from other energy source suppliers offering fuel oil, electricity and in some cases propane. Peoples Gas System has taken actions to retain and expand its commodity and transportation business, including managing costs and providing high-quality service to customers.
FINANCING ACTIVITY:
In the second quarter of 1998, Tampa Electric Company filed a registration statement for the issuance of up to $200 million of medium-term notes. In July 1998, Tampa Electric Company issued $50 million of Remarketed Notes, due 2038. The Notes, which bear an initial coupon rate of 5.94%, are subject to mandatory tender on July 15, 2001, at which time they will be remarketed or redeemed. Net proceeds were $51 million, which included a premium paid to Tampa Electric by the remarketing agent for the right to purchase the Notes in 2001. If this right is exercised, for the following 10 years the Notes will bear interest at 5.41% plus a premium based on Tampa Electric Company's then-current credit spread above United States Treasury Notes with 10 years to maturity.
Proceeds from the note issue were used to repay short-term debt and for general corporate purposes.
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING
In 1998, the FASB issued FAS 133, Accounting for Derivative Instruments and Hedging. This standard is effective for fiscal years beginning after June 15, 2000. The new standard, as amended, requires an entity to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in fair value of those instruments as either components of comprehensive income or in net income, depending on the types of those instruments.
In preparation for adoption of this Statement effective Jan. 1, 2001, the company has completed an analysis of the information required by FAS 133. The company has determined that such activity has been minimal and relatively short term in duration. From time to time, Tampa Electric has entered into futures, swaps and options contracts to moderate its exposure to interest rate changes. The benefits of these arrangements are at risk only in the event of non-performance by the other party to the agreement, which the company does not anticipate.
Based on policies and procedures approved by the Board of Directors, from time to time the company enters into futures, swaps and option contracts to limit exposure to gas price increases at the regulated natural gas utility. The benefits of these arrangements are at risk only in the event of non-performance by the other party to the agreement, which the company does not anticipate.
At this point, the company does not anticipate that the adoption of FAS 133 will significantly impact its financial statements. Management will continue to document all current and possible future uses of derivatives, evaluate their effectiveness for hedging treatment and utilize procedures and methods for measuring them.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
Tampa Electric Company is exposed to changes in interest rates primarily as a result of its borrowing activities.
From time to time, Tampa Electric Company enters into futures, swaps and option contracts to moderate exposure to interest rate changes.
A hypothetical 10 percent increase in Tampa Electric Company's weighted average interest rate on its variable rate debt would not have a significant impact on Tampa Electric Company's pretax earnings over the next fiscal year.
A hypothetical 10 percent decrease in interest rates would not have a significant impact on the estimated fair value of Tampa Electric Company's long-term debt at Dec. 31, 1999.
Commodity Price Risk
Currently, at Tampa Electric and Peoples Gas System, commodity price increases due to changes in market conditions for fuel, purchased power and natural gas are recovered through cost recovery clauses, with no effect on earnings.
From time to time, Tampa Electric Company enters into futures, swaps and options contracts to limit exposure to gas price increases at the regulated natural gas utility.
Tampa Electric Company does not use derivatives or other financial products for speculative purposes.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
All other financial statement schedules have been omitted since they are not required, are inapplicable or the required information is presented in the financial statements or notes thereto.
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To the Board of Directors of Tampa Electric Company
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Tampa Electric Company and its subsidiaries, (a wholly owned subsidiary of TECO Energy, Inc.) at Dec. 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended Dec. 31, 1999, in conformity with accounting principles generally accepted in the United States. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respect, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Tampa, Florida Jan. 14, 2000
CONSOLIDATED BALANCE SHEETS (MILLIONS)
The accompanying notes are an integral part of the consolidated financial statements.
CONSOLIDATED STATEMENTS OF INCOME (MILLIONS)
The accompanying notes are an integral part of the consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS (MILLIONS)
The accompanying notes are an integral part of the consolidated financial statements.
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (MILLIONS)
The accompanying notes are an integral part of the consolidated financial statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
- ----------------- (1) Quarterly dividends paid on Feb. 15, May 15, Aug. 15 and Nov. 15. (2) Millions.
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
(1) Composite year-end interest rate. (2) Tax-exempt securities. (3) Proceeds of these bonds were used to refund bonds with interest rates of 11 5/8% - 12 5/8%. For accounting purposes, interest expense has been recorded using blended rates of 8.28% - 8.66% on the original and refunding bonds, consistent with regulatory treatment. (4) Proceeds of these bonds were used to refund bonds with an interest rate of 9.9% in February 1995. For accounting purposes, interest expense has been recorded using a blended rate of 6.52% on the original and refunding bonds, consistent with regulatory treatment. (5) These notes are subject to mandatory tender on July 15, 2001, at which time they will be redeemed or remarketed. (6) These long-term debt agreements contain various restrictive covenants, including provisions related to interest coverage, maximum levels of debt to total capitalization and limitations on dividends. (7) Of the amount due in 2000, $0.8 million may be satisfied by the substitution of property in lieu of cash payments.
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
Substantially all of the property, plant and equipment of the company is pledged as collateral. Maturities and annual sinking fund requirements of long-term debt for the years 2001, 2002, 2003 and 2004 are $55.2 million, $6.0 million, $186.5 million, and $6.5 million, respectively. Of these amounts $.8 million per year for 2001 through 2004 may be satisfied by the substitution of property in lieu of cash payments.
At Dec. 31, 1999, total long-term debt had a carrying amount of $690.3 million and an estimated fair market value of $721.6 million. The estimated fair market value of long-term debt was based on quoted market prices for the same or similar issues, on the current rates offered for debt of the same remaining maturities, or for long-term debt issues with variable rates that approximate market rates, at carrying amounts. The carrying amount of long-term debt due within one year approximated fair market value because of the short maturity of these instruments.
The accompanying notes are an integral part of the consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF ACCOUNTING
Tampa Electric Company's regulated electric and gas operations maintain their accounts in accordance with recognized policies prescribed or permitted by the Florida Public Service Commission (FPSC). In addition, Tampa Electric maintains its accounts in accordance with recognized policies prescribed or permitted by the Federal Energy Regulatory Commission (FERC). These policies conform with generally accepted accounting principles in all material respects.
The impact of Financial Accounting Standard (FAS) No. 71, Accounting for the Effects of Certain Types of Regulation, has been minimal in the experience of the regulated utilities, but when cost recovery is ordered over a period longer than a fiscal year, costs are recognized in the period that the regulatory agency recognizes them in accordance with FAS 71. Also as provided in FAS 71, Tampa Electric has deferred revenues in accordance with the various regulatory agreements approved by the FPSC in 1995, 1996 and 1999. Revenues are recognized as allowed in 1997, 1998 and 1999 under the terms of the agreements.
The regulated utilities' retail business is regulated by the FPSC, and Tampa Electric's wholesale business is regulated by FERC. Prices allowed, with respect to Tampa Electric, by both agencies are generally based on the recovery of prudent costs incurred plus a reasonable return on invested capital.
The use of estimates is inherent in the preparation of financial statements in accordance with generally accepted accounting principles.
REVENUES AND FUEL COSTS
Revenues include amounts resulting from cost recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased capacity, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline capacity and conservation costs for Peoples Gas System. These adjustment factors are based on costs projected for a specific recovery period. Any over-recovery or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as deferred credits, and under-recoveries of costs are recorded as deferred charges.
In August 1996, the FPSC approved Tampa Electric's petition for recovery of certain environmental compliance costs through the Environmental Cost Recovery Clause.
In December 1994, Tampa Electric bought out a long-term coal supply contract which would have expired in 2004 for a lump sum payment of $25.5 million and entered into two new contracts with the supplier. The coal supplied under the new contracts is competitive in price with coal of comparable quality. As a result of this buyout, Tampa Electric customers will benefit from anticipated net fuel savings of more than $40 million through the year 2004. In February 1995, the FPSC authorized the recovery of the $25.5-million buy-out amount plus carrying costs through the Fuel and Purchased Power Cost Recovery Clause over the 10-year period beginning April 1, 1995. In each of the years 1999, 1998 and 1997, $2.7 million of buy-out costs were amortized to expense.
Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed.
The regulated utilities accrue base revenues for services rendered but unbilled to provide a closer matching of revenues and expenses.
In May 1996, the FPSC issued an order approving an agreement among Tampa Electric, the Office of Public Council (OPC) and the Florida Industrial Power Users Group (FIPUG) regarding 1996 earnings. This agreement provided for a $25-million revenue refund to customers to be made over the 12-month period beginning Oct. 1, 1996. This refund consisted of $15 million of revenues deferred from 1996 and $10 million of revenues deferred from 1995, plus accrued interest.
In October 1996, the FPSC approved an agreement among Tampa Electric, OPC and FIPUG that resolved all pending regulatory issues associated with the Polk Power Station. The agreement allowed the full recovery of the capital costs incurred in the construction of the Polk Power Station project, and called for an extension of the base rate freeze established in the May agreement through 1999. The October agreement also established a $25-million temporary base rate reduction reflected as a credit on customer bills over a 15-month period. The reduction began Oct. 1, 1997 which immediately followed the $25-million refund in the May agreement.
DEPRECIATION
The company provides for depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage, of depreciable property over its estimated service life. The provision for utility plant in service, expressed as a percentage of the original cost of depreciable property, was 4.0% for 1999, 4.1% for 1998 and 4.0% for 1997.
The original cost of utility plant retired or otherwise disposed of and the cost of removal less salvage are charged to accumulated depreciation.
ASSET IMPAIRMENT
The company periodically assesses whether there has been a permanent impairment of its long-lived assets and certain intangibles held and used by the company, in accordance with FAS 121, Accounting for the Impairment of Long-lived Assets and Long-Lived Assets to be Disposed of. No write-down of assets due to impairment was required in 1999 or 1998.
REPORTING COMPREHENSIVE INCOME
The company has adopted FAS 130, Reporting Comprehensive Income. This standard requires that comprehensive income, which includes net income as well as certain changes in assets and liabilities recorded in common equity, be reported in the financial statements. There were no components of comprehensive income other than net income for the years ended Dec. 31, 1999 and 1998.
REPORTING ON THE COSTS OF START-UP ACTIVITIES
In 1999, the company adopted AICPA Statement of Position (SOP) 98-5, Reporting on the Costs of Start-up Activities. It requires costs of start-up activities and organization costs to be expensed as incurred. Start-up activities are broadly defined as those one-time activities related to events such as opening a new facility, conducting business in a new territory and organizing a new entity. Some costs, such as the costs of acquiring or constructing long-lived assets and bringing them into service, are not subject to SOP 98-5. The costs expensed in 1999 in accordance with SOP 98-5 were not significant.
ACCOUNTING FOR CONTRACTS INVOLVED IN ENERGY TRADING AND RISK MANAGEMENT ACTIVITIES
In 1998, the FASB's Emerging Issues Task Force (EITF) released Issue 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, effective for fiscal years beginning after Dec. 15, 1998. EITF 98-10 requires contracts for the purchase and sale of energy commodities that are determined to be trading activities or contracts as defined in the Issue, be valued at market on the balance sheet date, and the resulting gain or loss reflected in earnings. At Dec. 31, 1999, the company does not have any contracts for the purchase or sale of energy that would be classified as trading activities as defined in EITF 98-10.
DEFERRED INCOME TAXES
The liability method is utilized in the measurement of deferred income taxes. Under the liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at current tax rates. Tampa Electric and Peoples Gas System are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates.
INVESTMENT TAX CREDITS
Investment tax credits have been recorded as deferred credits and are being amortized to income tax expense over the service lives of the related property.
OTHER DEFERRED CREDITS
Other deferred credits primarily include the accrued postretirement benefit liability, the pension liability and minority interest.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric's cost of capital. The rate was 7.79% for 1999, 1998 and 1997. Total AFUDC for 1999 and 1997 was $1.8 million and $0.2 million, respectively. There were no qualifying projects in 1998. The base on which AFUDC is calculated excludes construction work in progress which has been included in rate base.
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING
In 1998, the Financial Accounting Standards Board (FASB) issued Financial Accounting Standard (FAS) 133, Accounting for Derivative Instruments and Hedging. This standard was initially to be effective for fiscal years beginning after June 15, 1999. In July 1999, the FASB delayed the effective date of this pronouncement until fiscal years beginning after June 15, 2000. The new standard requires an entity to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in fair value of those instruments as either components of comprehensive income or in net income, depending on the types of those instruments.
In preparation for adoption of this Statement effective Jan. 1, 2001, the company has completed an initial review of business activities and contracts, and has developed a preliminary inventory of derivative instruments encompassed by FAS 133. The company has found that such activity has been minimal and relatively short-term in duration. From time to time, the company has entered into futures, swaps and options contracts to limit exposure to gas price increases at both the regulated natural gas utility and unregulated propane business. As of Dec. 31, 1999, the company had hedging transactions in place to protect against purchase price variability of natural gas at Peoples Gas. Tampa Electric Company has not used derivatives or other financial products for speculative purposes.
At this point, the company does not anticipate that the adoption of FAS 133 will significantly impact its financial statements. Management will continue to document all current and possible future uses of derivatives, evaluate their effectiveness for hedging treatment, and develop procedures and methods for measuring them.
MERGERS
In June 1997, TECO Energy, Inc. completed its merger with Lykes Energy, Inc. Concurrent with this merger, the regulated gas distribution utility, Peoples Gas System, Inc., was merged into Tampa Electric Company and now operates as the Peoples Gas System division of Tampa Electric Company.
Also in June 1997, TECO Energy completed its merger with West Florida Gas Inc. (West Florida). Concurrent with this merger, West Florida's regulated gas distribution utility, West Florida Natural Gas Company, was merged into Tampa Electric Company and now operates as part of the Peoples Gas System division.
These mergers were accounted for as poolings of interests and, accordingly, the company's Balance Sheet as of Dec. 31, 1997 and its Statements of Income and Cash Flows for the period ended Dec. 31, 1997 include the results of Peoples Gas System and West Florida.
Financial statements and all financial information presented for periods prior to 1997 have been restated to include the results of the Peoples Gas System. Prior period financial statements have not been restated to reflect the operations and financial position of West Florida Natural Gas due to its size.
RECLASSIFICATIONS
Certain prior year amounts were reclassified to conform with current year presentation.
B. COMMON STOCK
The company is a wholly owned subsidiary of TECO Energy, Inc.
(1) In July 1997, Tampa Electric retired all of its outstanding shares ($20 million aggregate par value) of 4.32% Series A. 4.16% Series B and 4.58% Series D preferred stock at redemption prices of $103.75, $102.875 and $101.00 per share, respectively. In connection with this retirement, $.1 million of associated issuance costs were recognized.
C. RETAINED EARNINGS
Tampa Electric's first mortgage bonds and certain of Peoples Gas System's long-term debt issues contain provisions that limit the dividend payment on the company's common stock. At Dec. 31, 1999, substantially all of the company's retained earnings were available for dividends on its common stock.
D. RETIREMENT PLAN
Tampa Electric is a participant in the comprehensive retirement plan of TECO Energy, including a non-contributory defined benefit retirement plan which covers substantially all employees. Benefits are based on employees' years of service and average final salary.
TECO Energy's policy is to fund the plan within the guidelines set by ERISA for the minimum annual contribution and the maximum allowable as a tax deduction by the IRS. About 73 percent of plan assets were invested in common stocks and 27 percent in fixed income investments at Dec. 31, 1999.
The Peoples Gas System retirement plan was merged with the TECO Energy retirement plan effective Jan. 1, 1998. As of Dec. 31, 1997, Peoples Gas System had a non-contributory defined benefit retirement plan which covered substantially all employees. Benefits were based on employees' years of service and average compensation during specified years of employment.
Peoples Gas System's retirement plan was funded annually by the company within the guidelines set by ERISA for the minimum annual contribution and the maximum allowable as a tax deduction by the IRS. Plan assets were invested primarily in a collective investment trust consisting of equity securities, fixed income securities and cash equivalents.
All information prior to 1998 has been restated to include the Peoples Gas System Retirement Plan.
In 1997, the Financial Accounting Standards Board issued FAS 132, Employers' Disclosures about Pensions and Other Post Retirement Benefits. FAS 132 standardizes the disclosure requirements for pension and other postretirement benefits with additional information required on changes in the benefit obligations and fair values of plan assets. TECO Energy adopted FAS 132 with the additional disclosures included here and in Footnote E, Postretirement Benefit Plan.
Components of net pension expense, reconciliation of the funded status and the accrued pension liability are presented below for TECO Energy consolidated.
(1) Tampa Electric Company's portion was $1.8 million, $2.1 million and $2.6 million for 1999, 1998 and 1997, respectively.
RECONCILIATION OF THE FUNDED STATUS OF THE RETIREMENT PLAN AND THE ACCRUED PENSION PREPAYMENT/(LIABILITY) (MILLIONS)
ASSUMPTIONS USED IN DETERMINING ACTUARIAL VALUATIONS
E. POSTRETIREMENT BENEFIT PLAN
Tampa Electric Company currently provides certain postretirement health care benefits for substantially all employees retiring after age 55 meeting certain service requirements. The company contribution toward health care coverage for most employees retiring after Jan. 1, 1990 is limited to a defined dollar benefit based on years of service. Postretirement benefit levels are substantially unrelated to salary. Tampa Electric Company reserves the right to terminate or modify the plan in whole or in part at any time. The prior period amounts have been restated to include life insurance benefits.
RECONCILIATION OF THE FUNDED STATUS OF THE POSTRETIREMENT BENEFIT PLAN AND THE ACCRUED LIABILITY (MILLIONS)
ASSUMPTIONS USED IN DETERMINING ACTUARIAL VALUATIONS
The assumed health care cost trend rate for medical costs prior to age 65 was 8.0% in 1999 and decreases to 5.75% in 2002 and thereafter. The assumed health care cost trend rate for medical costs after age 65 was 6.5% in 1999 and decreases to 5.75% in 2002 and thereafter.
A 1-percent increase in the medical trend rates would produce a 6-percent ($0.4 million) increase in the aggregate service and interest cost for 1999 and a 5-percent ($3.3 million) increase in the accumulated postretirement benefit obligation as of Dec. 31, 1999.
A 1-percent decrease in the medical trend rates would produce a 5-percent ($0.4 million) decrease in the aggregate service and interest cost for 1999 and a 4-percent ($2.9 million) decrease in the accumulated postretirement benefit obligation as of Dec. 31, 1999.
F. INCOME TAX EXPENSE
The company is included in the filing of a consolidated Federal income tax return with its parent and affiliates. The company's income tax expense is based upon a separate return computation. Income tax expense consists of the following components:
Deferred taxes result from temporary differences in the recognition of certain liabilities or assets for tax and financial reporting purposes. The principal components of the company's deferred tax assets and liabilities recognized in the balance sheet are as follows:
- ----------------- (1) Certain property related assets and liabilities have been netted.
The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons:
G. SHORT-TERM DEBT
Notes payable consisted primarily of commercial paper with weighted average interest rates of 5.95% and 5.18% at Dec. 31, 1999 and 1998, respectively. The carrying amount of notes payable approximated fair market value because of the short maturity of these instruments. Unused lines of credit at Dec. 31, 1999 were $230 million. Certain lines of credit require commitment fees of .05% on the unused balances.
H. RELATED PARTY TRANSACTIONS (millions)
Net transactions with affiliates are as follows:
Amounts due from or to affiliates of the company at year-end are as follows:
Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.
I. CHARGES TO EARNINGS
In 1999 and 1998 the company recognized certain charges that were unusual and nonrecurring in nature.
1999 CHARGES
The charges in 1999 totaled $18.3 million pretax ($13.7 million after tax) and consisted of the following:
Tampa Electric recorded a charge of $10.5 million ($6.4 million after tax) based on FPSC audits of its 1997 and 1998 earnings, which among other things, limited its regulatory equity ratio to 58.7 percent, a decrease of 91 basis points and 224 basis points from 1997's and 1998's ratios, respectively.
Tampa Electric also recorded a charge of $3.5 million after tax, representing management's estimate of additional expense to resolve the litigation filed by the United States Environmental Protection Agency.
A net after-tax charge, after recovery under the then current regulatory agreement totaling $3.8 million was also recognized reflecting corporate income tax provisions and settlements related to prior years' tax returns.
1998 CHARGES
In 1998, TECO Energy recognized charges totaling $16.9 million, pretax ($10.3 million, after tax). These charges consisted of the following:
The FPSC in September 1997 ruled that under the regulatory agreements effective through 1999 the costs associated with two long-term wholesale power sales contracts should be assigned to the wholesale jurisdiction and that for retail rate making purposes the costs transferred from retail to wholesale should reflect average costs rather than the lower incremental costs on which the two contracts are based. As a result of this decision and the related reduction of the retail rate base upon which Tampa Electric is allowed to earn a return, these contracts became uneconomic. One contract was terminated in 1997. As to the other contract, which expires in 2001, Tampa Electric entered into firm power purchase contracts with third parties to provide replacement power through 1999 and is no longer separating the associated generation assets from the retail jurisdiction. The cost of purchased power under these contracts exceeded the revenues expected through 1999. To reflect this difference, Tampa Electric recorded a $9.6 million charge ($5.9 million after tax) in 1998. In November 1999, the FPSC approved a company-proposed treatment for the remaining 14 1/2 months of the contract that flows 100 percent of the revenues from the contract back to retail customers.
Tampa Electric also recorded a charge of $7.3 million ($4.4 million after tax) in other expense for an FPSC decision in 1998 denying recovery of certain BTU coal quality price adjustments for coal purchases from TECO Coal since 1993.
J. COMMITMENTS AND CONTINGENCIES
Tampa Electric's capital investments are estimated to be $141 million in 2000 and $540 million for 2001 through 2004 for equipment and facilities to meet customer growth and generation reliability programs. Additionally, Tampa Electric is also expecting to spend $51 million in 2000 and $554 million during 2001-2004 to repower the Gannon Power Station and is forecasting $42 million in 2000 and $114 million during 2001-2004 to construct additional generation expansion. At the end of 1999, Tampa Electric had outstanding commitments of about $66 million to repower the Gannon Power Station.
Peoples Gas System's capital investments are estimated to be $66 million for 2000 and $211 million for 2001 through 2004 for infrastructure expansion to grow the customer base and normal asset replacement.
Tampa Electric Company is a potentially responsible party for certain superfund sites and, through its Peoples Gas System division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, Tampa Electric Company estimates its ultimate financial liability at approximately $20 million over the next 10 years. The environmental remediation costs associated with these sites are not expected to have a significant impact on customer prices.
K. SEGMENT INFORMATION
Tampa Electric Company is a public utility operating within the state of Florida. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to more than 552,000 customers in West Central Florida. Its Peoples Gas System division is engaged in the purchase, distribution and marketing of natural gas for almost 253,000 residential, commercial, industrial and electric power generation customers in the State of Florida. FAS 131 was adopted in 1998 and all prior years presented here have been restated to conform to the requirements of FAS 131.
(1) Operating income is net of income tax expense. Total income tax expense was $81.7 million, $86.3 million and $87.5 million in 1999, 1998 and 1997, respectively. (2) Revenues from sales to affiliates were $24.1 million, $23.2 million and $22.2 million in 1999, 1998 and 1997, respectively. (3) Revenues shown in 1999 include the reversal of previously deferred revenue of $11.9 million. Revenues shown in 1998 and 1997 include the recognition of previously deferred revenue of $38.3 million and $30.5 million, respectively. (4) Revenues and Operating income as shown for 1999 exclude a $7.9 million credit resulting from a non-recurring charge. See Note I. (5) Operating income excludes a non-recurring pretax charge of $9.6 million in 1998. See Note I. (6) Net income excludes non-recurring after tax charges totaling $13.7 million and $10.3 million in 1999 and 1998, respectively. See Note I.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
During the period Jan. 1, 1998 to the date of this report, the company has not had and has not filed with the Commission a report as to any changes in or disagreements with accountants on accounting principles or practices, financial statement disclosure, or auditing scope or procedure.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) 1. Financial Statements - See index on page 21. 2. Financial Statement Schedules - See index on page 21.
TAMPA ELECTRIC COMPANY
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEARS ENDED DEC. 31, 1999, 1998 AND 1997 (millions)
- ------------- (1) Write-off of individual bad debt accounts
3. Exhibits
- ------------- * Indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. Exhibits filed with periodic reports of Tampa Electric Company and TECO Energy, Inc. were filed under Commission File Nos. 1-5007 and 1-8180, respectively.
Certain instruments defining the rights of holders of long-term debt of Tampa Electric Company authorizing in each case a total amount of securities not exceeding 10 percent of total assets on a consolidated basis are not filed herewith. Tampa Electric Company will furnish copies of such instruments to the Securities and Exchange Commission upon request.
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS
Exhibits 10.1 through 10.26 above are management contracts or compensatory plans or arrangements in which executive officers or directors of TECO Energy, Inc. and its subsidiaries participate.
(b) REPORTS ON FORM 8-K
Tampa Electric Company filed the following reports on Form 8-K during the last quarter of 1999.
The registrant filed a Current Report on Form 8-K dated Dec. 7, 1999 reporting under "Item 5. Other Events" announcing Tampa Electric Company's 10-year environmental program.
Subsequent to Dec. 31, 1999, Tampa Electric Company filed the following reports on Form 8-K.
The registrant filed a Current Report on Form 8-K dated Feb. 29, 2000, reporting under "Item 5. Other Events" announcing Tampa Electric Company's agreement with the U.S. Environmental Protection Agency and the U.S. Department of Justice to resolve the federal agencies' pending enforcement actions against the 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 on the 29th day of March, 2000.
TAMPA ELECTRIC COMPANY
By R. D. FAGAN* ------------------------------------ R. D. FAGAN, Chairman of the Board, Director and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on March 29, 2000:
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT
No annual report or proxy material has been sent to Tampa Electric Company's security holders, since all of its equity securities are held by TECO Energy, Inc.
INDEX TO EXHIBITS
- ------------- * Indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. Exhibits filed with periodic reports of Tampa Electric Company and TECO Energy, Inc. were filed under Commission File Nos. 1-5007 and 1-8180, respectively.