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 June 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 s t ate 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 marketing 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. 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. Total net winter generating capability at Dec. 31, 1998 is 3,615 megawatts (MWs). PGS, with 240,000 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 1998 was 912 million therms. P o w er 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 1998 were not significant.
TAMPA ELECTRIC--Electric Operations
Tampa Electric had 2,833 employees as of Dec. 31, 1998, of which 1,089 were represented by the International Brotherhood of Electrical Workers (IBEW) and 334 by the Office and Professional Employees International Union. In 1998, approximately 46 percent of Tampa Electric's total operating revenue was derived from residential sales, 27 percent from commercial sales, 9 percent from industrial sales and 18 percent from other sales including bulk power sales for resale.
The sources of electric operating revenue for 1998 were as follows:
(millions) 1998
Residential $ 563.2 Commercial 335.2 Industrial-Phosphate 59.3 Industrial-Other 53.4 Other retail sales of electricity 86.9 Sales for resale 89.6 Deferred revenues 38.3 Other 8.7 $1,234.6
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 1998 base revenues. See the discussion of IMCA on page 25. Tampa Electric's business is not a seasonal one, 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, the 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 and preferred stock, 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 22 and 23. Fuel, conservation, certain environmental and certain purchased p o w e r costs are recovered through levelized monthly charges established pursuant to the FPSC's fuel adjustment and cost recovery clauses. These charges, which are reset annually in an FPSC hearing, 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 7 and 8. T E C O 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 residences and businesses and the self-generation option 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 1998, the FPSC approved a tariff for Tampa Electric that should assist in reducing the loss of existing at-risk load and assist in the acquisition of new load. The Commercial/Industrial Service Rider included in this tariff is a load retention, or economic development contract, that provides for flexible pricing to meet competitive alternatives available to existing or potential new customers. 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. 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 owning transmission facilities (including Tampa Electric) 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 page 25 for a further description of proposed projects and the issues involved.
Fuel
About 97 percent of Tampa Electric's generation for 1998 was from its coal-fired units. About the same level is anticipated for 1999. Tampa Electric's average fuel cost per million BTU and average cost per ton of coal burned for 1998 were as follows:
Average cost per million BTU: 1998
Coal $ 1.99 Oil $ 3.14 Composite $ 2.03 Average cost per ton of coal burned $44.44
Tampa Electric's generating stations burn fuels as follows: Gannon Station burns low-sulfur coal; Big Bend Station 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 7.9 million tons of coal during 1998 and estimates that its coal consumption will be about 8.1 m i llion tons for 1999. During 1998, Tampa Electric purchased approximately 41 percent of its coal under long-term contracts with six suppliers, including TECO Coal, and 59 percent of its coal in the spot market or under intermediate-term purchase agreements. About 9 percent of Tampa Electric's 1998 coal requirements were supplied by TECO Coal. During December 1998, the average delivered cost of coal (including transportation) was $41.37 per ton, or $1.78 per million BTU. Tampa Electric expects to obtain approximately 31 percent of its coal requirements in 1999 under long-term contracts with five suppliers, including TECO Coal, and the remaining 69 percent in the spot market or under intermediate-term purchase agreements. Tampa Electric estimates that about 7 percent of its 1999 coal requirements will be supplied by TECO Coal. Tampa Electric's 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 1998, about 66 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, 1998 for No. 2 fuel oil and No. 6 fuel oil for its Polk, Hookers Point and Phillips stations, and its four combustion turbine units at prices based on Gulf Coast Cargo spot prices. Contracts for the supply of No. 2 and No. 6 fuel oil through Dec. 31, 1999 are expected to be finalized in early 1999. The price for No. 2 fuel oil deliveries taken in December 1998 was $16.17 per barrel, or $2.79 per million BTU. The price for No. 6 fuel oil deliveries taken in December 1998 was $14.42 per barrel, or $2.28 per million BTU.
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 has the 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. 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. Tampa Electric has no reason to believe that any of these franchises will not be renewed. Franchise fees payable by Tampa Electric, which totaled $20.9 million in 1998, 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.
Environmental Matters
Tampa Electric's operations are subject to county, state and f e deral environmental regulations. The Hillsborough County Environmental Protection Commission and the Florida Environmental Regulation Commission are responsible for promulgating environmental regulations and coordinating most of the environmental regulation functions performed by the various departments of state government. T h e Florida Department of Environmental Protection (FDEP) is responsible for the administration and enforcement of the state regulations. The U.S. Environmental Protection Agency (EPA) is the primary federal agency with environmental responsibility. Tampa Electric believes that it has all required environmental permits. In addition, monitoring programs are in place to assure compliance with permit conditions. Tampa Electric has been identified as a potentially responsible party (PRP) for certain superfund sites. While the total costs of remediation at these sites may be significant, Tampa Electric shares potential liability with other PRPs, many of which have substantial assets. Accordingly, Tampa Electric expects that its liability in connection with these sites will not be significant. The environmental remediation costs associated with these sites are not expected to have a material impact on customer prices. The U.S. Environmental Protection Agency (EPA) has commenced an investigation of coal-fired electric power generators under the 1990 C l ean Air Act Amendments (CAAA) to determine compliance with e n v ironmental permitting requirements associated with repairs, m a intenance, modifications and operations changes made to the facilities over the years. The EPA's focus is on whether new source p e r formance standards should be applied to the changes and, accordingly, whether the best available control technology was or should have been used. Tampa Electric is one of several electric utilities that have been visited by EPA personnel and received a comprehensive request for information pursuant to Section 114 of EPA's Clean Air Act regulations. Tampa Electric is furnishing appropriate information. It believes that it has built, maintained and operated its facilities in compliance with relevant environmental permitting requirements. The timing of completion and the outcome of the EPA s investigation are uncertain. Expenditures. During the five years ended Dec. 31, 1998, Tampa E l e c tric spent $172.1 million on capital additions to meet environmental requirements, including $108.2 million for the Polk Power Station project. Environmental expenditures are estimated at $9.9 million for 1999 and $8.8 million in total for 2000 through 2003. 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 b l e nds of lower-sulfur coal, controlling stack emissions and purchasing emission allowances. In 1998, Tampa Electric decided to add a flue gas desulfurization (FGD) system, or "scrubber," in order to comply with Phase II of the CAAA. The $83-million scrubber will reduce the amount of sulfur dioxide emitted by Tampa Electric's Big Bend Units One and Two and will allow significant fuel savings at other Tampa Electric units. As a result of this project, all of the units at Big Bend Station, Tampa Electric's largest generating station, will be equipped with scrubber technology. Tampa Electric has spent approximately $16 million on this project in 1998 and estimates capital expenditures related to this scrubber to be $61 million in 1999 and $6 million thereafter.
The FPSC approved the FGD system as the most cost effective a l t e rnative for Tampa Electric to meet its CAAA compliance requirements and the recovery of prudently incurred costs through the environmental cost recovery clause. Cost recovery will not begin, however, until the FGD system is in service and Tampa Electric has applied for such recovery specifying the costs actually incurred. 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.. In 1998, Tampa Electric recovered $5.4 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. Under the October 1996 agreement with the FPSC, the earliest any new prices could be in effect to cover such costs is in the year 2000.
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 distribution system that serves approximately 240,000 customers. The system includes approximately 7,300 miles of mains and over 4,800 miles of service lines. In 1998, industrial and power generation customers consumed approximately 65 percent of PGS' annual therm volume. Commercial customers use approximately 29 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 24 p e r c ent 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 F l orida, 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 a b o ut 300 million therms annually to facilities involved in cogeneration.
Revenues for PGS for 1998 were as follows:
(millions) 1998 Residential $ 57.7 Commercial 141.2 Industrial 20.9 Power Generation 10.4 Other revenues 22.6 Total $252.8
PGS had 897 employees as of Dec. 31, 1998. A total of 128 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, which 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 charges (both reservation and usage) it pays for transportation of gas for system supply through the purchased gas adjustment charge. 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, which are reset annually in an FPSC hearing, are 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 addition to its base rates and purchased gas adjustment clause c h a r g es 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 September 1998, the FPSC staff circulated a proposed rule that would require natural gas utilities to offer transportation-only service to all non-residential customers. The proposed rule is vague
and does not prescribe any method for achieving this requirement. 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 February 1999, the FPSC approved PGS petition to expand for a two-year period its existing, experimental unbundling program to a maximum of 1,000 customers from the current 170 customers for two years. 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 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. 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 f a c i lities, 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 for further delivery by PGS to its customers through two interstate pipelines on which PGS has reserved firm transportation capacity. Gas is delivered by Florida Gas Transmission 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 pipeline through a gate station located northwest of Jacksonville. PGS has commitments for pipeline capacity with various expiration dates. 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 d i s tribution system, and on extremely cold days, which have historically been rare in Florida. 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. The current supply portfolio consists of approximately 1 percent spot purchases, 17 percent swing purchases and 82 percent base load purchases. PGS has one long-term supply contract which expires in 2002. This long-term contract has approximately 58 million therms remaining to be purchased with a total cost of $12.7 million over the remaining years. The purchase price is $.22 per therm. 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 t h e c u stomer 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 has the 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. 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 April 1999 through June 2028. In January 1999, the City of Lakeland notified PGS that it was considering exercising its right to purchase PGS property in the Lakeland franchise area when its franchise agreement with PGS expires in March 2000. PGS serves approximately 5,000 customers in Lakeland. PGS has commenced discussions with the City of Lakeland 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. PGS has no reason to believe that any of its other franchises will not be renewed. Franchise fees payable by PGS, which totaled $7.9 million in 1 9 9 8, 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. U t ility 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 to 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. PGS has been identified as a potentially responsible party for certain former manufactured gas plant sites. The joint and several liability associated with these sites presents the potential for significant response costs; PGS estimates its ultimate financial liability of approximately $20 million over the next ten years. To date, PGS has been permitted by the FPSC to recover prudently incurred costs of environmental remediation and cleanup associated with these manufactured gas sites. The environmental remediation costs associated with these sites are not expected to have a material 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, 1998, PGS has not incurred any material capital additions to meet environmental requirements, nor are any anticipated for 1999 through 2003.
Item 2.
Item 2. PROPERTIES.
The company believes that its 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, 1998, Tampa Electric had five electric generating plants and four combustion turbine units in service with a total net winter generating capability of 3,615 megawatts, including Big Bend ( 1 , 742-MW capability from four coal units), Gannon (1,180-MW capability from six coal units), Hookers Point (215-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 was placed on long-term reserve standby. T a m pa Electric owns 182 substations having an aggregate transformer capacity of 16,368,281 KVA. The transmission system c o n s ists of approximately 1,196 pole miles of high voltage transmission lines, and the distribution system consists of 6,905 pole miles of overhead lines and 2,741 trench miles of underground lines. As of Dec. 31, 1998, there were 537,107 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 m a i ntenance 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 more than 12,100 miles of pipe, including approximately 7,300 miles of mains and over 4,800 miles of service lines. P G S 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.
None.
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 $147.5 million in 1998 and $145.9 million for 1997. See Note C on page 39 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 r e gulations 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, 1998, 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. The amounts presented for 1996 have been restated to reflect the merger with Peoples Gas System, Inc. 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 1998 of $146.4 million declined 1 percent from 1997's results. The 1998 results included a first quarter after-tax charge of $5.9 million and a fourth quarter after-tax charge of $4.4 million. Net income for 1997 of $148.6 million declined 4 percent from 1996's restated results due primarily to an FPSC decision directing the regulatory treatment of two wholesale power sales contracts. One-time charges in 1998 at Tampa Electric reflected charges associated with ongoing actions to mitigate the effects of a 1997 FPSC ruling that separated two wholesale power sales contracts from the retail jurisdiction through 1999, 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 E l ectric - Electric Operating Results section, to change the regulatory treatment of two wholesale power sales contracts. Operating income, excluding a $9.6-million one-time, pretax charge, grew 5.3 percent in 1998 reflecting good growth from a strong local economy, expansion of the gas system and the recognition of $38.3 million of previously deferred revenues at Tampa Electric. For a description of the origination and treatment of deferred revenues, see Utility Regulation - Rate Stabilization Strategy section. 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. In 1996, Tampa Electric deferred $34.2 million of revenues under agreements approved by the FPSC. See Utility Regulation - Rate Stabilization Strategy section.
Contributions by Operating Division
(millions) 1998 Change 1997 Change 1996 Operating income Tampa Electric $ 203.4(1) 5.3% $ 193.1 11.9% $ 172.6 Peoples Gas System 25.8 5.3% 24.5 4.3% 23.5 229.2 5.3% 217.6 11.0% 196.1 Non-recurring charge (9.6) -- -- -- -- Total $ 219.6 .9% $ 217.6 11.0% $ 196.1
(1) Excludes one-time, pretax charge of $9.6 million for treatment of a wholesale contract.
Tampa Electric - Electric Operations
Tampa Electric's Operating Results
Tampa Electric's 1998 operating income, before the one-time charge, increased 5 percent from 1997, reflecting strong customer growth and continued strength in the local economy. Results in 1998 reflected recognition of $38.3 million of previously deferred revenues. In 1997, Tampa Electric benefited from a strong local economy, favorable customer growth and cost controls. Its 1997 operating income increased more than 11 percent, after the recognition of $30.5 million of previously deferred revenues.
Tampa Electric Results
(millions) 1998 Change 1997 Change 1996 Revenues(1) $1,234.6 3.8% $1,189.2 6.8% $1,112.9 Operating expenses 1,031.2(2) 3.5% 996.1 5.9% 940.3 Operating income $ 203.4 5.3% $ 193.1 11.9% $ 172.6
(1) Includes the recognition of $38.3 million and $30.5 million of previously deferred revenues in 1998 and 1997, respectively. 1996 revenues are net of $34.2 million of deferred revenues. (2) Excludes one-time, pretax charge of $9.6 million for treatment of a wholesale contract.
Tampa Electric's Operating Revenues Tampa Electric's 1998 operating revenues increased almost 4 percent, after the recognition of $38.3 million of previously deferred revenues. The company had customer growth of 2.3 percent and retail energy sales growth of more than 6 percent. Tampa Electric's 1997 revenues, including recognition of $30.5 million of previously deferred revenues, increased almost 7 percent, with customer growth increasing more than 2 percent and retail energy sales up 1 percent. The economy in Tampa Electric's service area continued to grow in 1998, with increased employment from corporate relocations and e x p ansions. Combined residential and commercial sales volumes increased over 7 percent in 1998, reflecting the addition of almost 12,000 customers and increased demand during warmer-than-normal summer weather. Combined residential and commercial energy sales declined slightly in 1997, as the effects of mild weather more than offset the addition of more than 12,000 new customers. Non-phosphate industrial sales increased in 1998 and 1997, 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 in 1998 were slightly below 1997 levels, reflecting a gradual migration of phosphate mining activity out of Tampa Electric's service area. Revenues from the phosphate customer group represented slightly more than 3 percent of base revenues in 1998. Non-fuel revenues from sales to other utilities were $36 million in 1998, $39 million in 1997 and $36 million in 1996. The non-fuel revenue increase in 1997 reflected the shift from broker system economy sales to longer-term higher-margin wholesale power sales. Megawatt hours sold to other utilities decreased in 1998 primarily because higher retail energy sales absorbed more generation capacity, and were lower in 1997 due to lower Tampa Electric generating unit availability. The decrease in non-fuel revenue in 1998 is the result of lower sales volumes and a shift from longer-term sales to shorter- term sales, because of an adverse FPSC decision in late 1997, described in the Utility Regulation - Wholesale Power Sales Contracts section. Tampa Electric will concentrate its prospective wholesale power sales efforts on energy broker or other short-term sales, and not on longer-term capacity contracts as was the case prior to this ruling. The FPSC decision, which required Tampa Electric to change the regulatory treatment of two wholesale power sales contracts, had the effect of reducing Tampa Electric's 1997 earnings by about $6.5 million, after tax. The company terminated one contract and incurred an after-tax charge of $5.9 million in 1998 for actions to mitigate the effect of this treatment on the second contract.
Tampa Electric Megawatt-Hour Sales
(thousands) 1998 Change 1997 Change 1996 Residential 7,050 8.5% 6,500 -1.6% 6,607 Commercial 5,173 5.5% 4,901 1.8% 4,815 Industrial 2,520 2.2% 2,466 7.0% 2,304 Other 1,284 5.0% 1,223 1.7% 1,203 Total retail 16,027 6.2% 15,090 1.1% 14,929 Sales for resale 2,486 -21.3% 3,160 -2.5% 3,241 Total energy sold 18,513 1.4% 18,250 .4% 18,170
Retail customers (average) 530.3 2.3% 518.4 2.4% 506.0
Tampa Electric's Operating Expenses Non-fuel operation and maintenance expenses increased almost 7 percent in 1998. Required expenditures to enhance system reliability and timing of generation station outages contributed to an increase of over $16 million in maintenance expense. Other operation expenses were essentially level with 1997, the result of effective cost management and improved efficiency throughout the company. In September 1996, Tampa Electric completed construction of the 250-megawatt, state-of-the-art, clean-coal technology Polk Unit One. The FPSC has allowed full recovery of capital costs and operating expenses associated with the plant as described in the Utility Regulation - Rate Stabilization Strategy section. The addition of this facility was the primary reason for the increased non-fuel operating expenses in 1997. Through 1998, a total of $21 million from the U.S. Department of Energy (DOE) was received to partially offset a s i gnificant portion of the non-fuel operation and maintenance expenses. For 1999, approximately $7 million in funds are available from the DOE.
Operating Expenses
(millions) 1998 Change 1997 Change 1996 Other operating expenses $ 165.8 .4% $165.1 .6% $164.1 Maintenance 94.6 21.0% 78.2 19.4% 65.5 Depreciation 146.1 3.3% 141.4 17.6% 120.2 Taxes-federal and state income 76.3 -2.8% 78.5 10.1% 71.3 Taxes, other than income 97.2 5.9% 91.8 5.5% 87.0 Operating expenses 580.0 4.5% 555.0 9.2% 508.2 Fuel 366.5 -1.8% 373.4 -2.5% 383.1 Purchased power 84.7 25.1% 67.7 38.2% 49.0 Total fuel expense 451.2 2.3% 441.1 2.1% 432.1 Total operating expenses $1,031.2 3.5% $996.1 5.9% $940.3
Reflecting normal plant additions to serve the growing customer base, depreciation expense increased by $4.7 million in 1998. Depreciation expense increased $21 million in 1997 due to normal plant additions and a full year of service of Polk Unit One. Depreciation expense is projected to rise moderately for the next several years due to normal additions to utility plant, as well as the addition of a flue gas desulfurization system in 2000. See Environmental Compliance section. Income taxes decreased in 1998 primarily due to lower pretax income. The increase in 1997's income tax expense from 1996 is due to higher pretax income and the effect of lower AFUDC on equity funds. Taxes other than income increased in 1998 as a result of higher gross receipts taxes and franchise fees related to higher energy sales. These taxes are recovered through customer bills. In 1997, changes in taxes other than income reflected the property taxes associated with Polk Unit One. Total fuel expense and purchased power increased in 1998 and 1997 due to higher energy sales. Average coal costs, on a cents-per-million BTU basis, increased 1.3 percent in 1998 after a 2.4 percent decrease in 1997. The overall success in controlling system fuel expense is a result of Tampa Electric's use of lower-priced coals, the mix in operating generating units and favorable prices in spot coal markets. In 1998, the FPSC disallowed, retroactively to 1992, certain quality adjustments for coal purchased from a Tampa Electric affiliate, resulting in a one-time pretax nonoperating charge of $7.3 million.
Purchased power increased in 1998 due to weather-related demand and the provision of replacement power for certain wholesale power sales contracts. In 1997, purchased power increased primarily due to lower generating unit availability. 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. On a total energy supply basis, self-generation accounted for 92 percent of the total system energy requirement in 1998.
Peoples Gas System
Peoples Gas System Results PGS achieved operating income growth of 5 percent over 1997, with the increase due primarily to 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 the 1998 decision to exit the appliance sales and service business. Operating income grew 4 percent in 1997 over 1996, reflecting increased customers, effective cost control and the acquisition of West Florida Natural Gas Company (WFNG). These factors were somewhat offset by the mild weather early in 1997. The actual cost of gas and upstream transportation purchased and resold to end-use customers is recovered through a Purchased Gas Adjustment clause approved by the FPSC.
Peoples Gas System Results(1)
(millions) 1998 Change 1997 Change 1996
Revenues $252.8 1.3% $249.5 -3.5% $258.6 Cost of gas sold 115.4 -3.5% 119.6 -8.1% 130.1 Operating expenses 111.6 5.9% 105.4 .4% 105.0 Operating income $ 25.8 5.3% $ 24.5 4.3% $ 23.5
Therms sold (millions)-by Customer Segment
Residential 52.7 7.8% 48.9 1.5% 48.2 Commercial 266.0 7.4% 247.6 3.9% 238.4 Industrial 305.0 5.7% 288.6 9.7% 263.2 Power Generation 288.3 -8.4% 314.7 7.7% 292.3 Total 912.0 1.4% 899.8 6.9% 842.1
Therms sold (millions)-By Sales Type
System Supply 320.8 9.6% 292.6 -14.5% 342.3 Transportation 591.2 -2.6% 607.2 21.5% 499.8 Total 912.0 1.4% 899.8 6.9% 842.1
Customers (thousands) 239.6 2.1% 234.7 16.0% 202.4
(1) 1996 data does not include the operating revenues and expenses, therms sold and customers of WFNG. WFNG was acquired in 1997 in a merger transaction accounted for as a pooling of interests. Prior-year financial results were not restated for the effects of this merger due to its size.
Residential gas sales increased in 1998, primarily as a result of overall customer growth and the addition of high-end customers throughout the year. Results reflected slightly warmer weather in 1998 compared to 1997. Residential gas sales increased in 1997 due to the addition of WFNG, partially offset by a mild winter which followed a much colder- than-normal winter in 1996. Operating revenues from residential and commercial customers grew almost 2 percent in 1998, while revenues from industrial and power generation customers were approximately 10 percent below last year. The increase in residential revenues was primarily due to higher average utilization per customer, reflecting the addition of high-end, multiple appliance customers. O p e rating expenses increased during 1998, reflecting restructuring costs totaling $3.4 million. These costs were primarily for early retirement and severance costs affecting 200 employees, associated with a decision in April to exit the appliance sales and service business. The restructuring, which was initiated in July, was completed and began to yield savings in ongoing expenses by the end of 1998. PGS began partnering with companies in an established dealer network to provide sales, installation and repair services to customers. PGS is the largest investor-owned gas distribution utility in Florida, with about 70 percent of the market. It serves almost 240,000 customers in all of the major metropolitan areas of Florida. PGS expects to invest an average of $50-60 million per year for the next five years to grow the business, roughly doubling the historical level of capital expenditures. Infrastructure is being expanded both in areas currently served and into areas not yet served by natural gas. In April 1998, PGS announced plans to expand into the Southwest Florida market providing service to Fort Myers, Naples, Cape Coral and surrounding areas. It is anticipated that 110,000 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 is expanding 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.
YEAR 2000 COMPUTER SYSTEMS READINESS:
Background There is a global awareness that many computer programs use only two digits to refer to a year and, therefore, may not correctly recognize and process date information beyond the year 1999. This is referred to as the "Year 2000" issue. The Year 2000 issue exists in two primary areas of Tampa Electric Company's operations: the critical business systems (such as the financial reporting, procurement, payroll and customer information and billing systems) and the control systems (such as those used in the operation of electric generation, transmission and distribution facilities). The company began work on Year 2000 readiness in August 1995. The project is segmented into the following phases: awareness, inventory, assessment, renovation, testing and contingency planning.
Readiness The company has completed its assessment of all hardware, software and embedded systems and is currently engaged in renovation, testing and contingency planning. Set forth below is a description of readiness by functional area.
Critical Business Systems The critical business systems, including mainframe hardware which was replaced in July 1998, have been substantially renovated and functionally tested. Mainframe integrated system testing has begun and is scheduled to be completed in the first half of 1999. To assist in assuring readiness, the renovation work and the integration testing are being handled by separate outside firms.
Control Systems The company's management believes that its transmission and distribution systems, including energy management and control and related embedded systems, are now ready for the Year 2000, i.e. renovated and tested to the extent necessary. The company retained industry specialty firms to assist with identifying areas where renovations were needed in the embedded systems associated with generator unit controls and with making these renovations. A number of successful unit tests have been conducted for Tampa Electric's generating units, and all required plant control system renovations are scheduled to be complete and tested by May 1999. Critical systems (those required for uninterrupted operations) have been renovated, with the exception of a portion of the Peoples Gas System control system , which is scheduled to be fully renovated and tested in the first half of 1999.
Coordination with Others The company has surveyed its largest suppliers (approximately 1,000) with respect to their Year 2000 readiness, including all providers of technology supplies and services, and plans to complete its customer survey process in the first half of 1999. As part of its Year 2000 project, the company will be coordinating with its suppliers and customers based on their responses to these surveys. A t the request of the DOE, the North American Electric Reliability Council (NERC) prepared a Year 2000 coordination plan and preliminary status report in September 1998 and updated it in January 1999. A full status report is expected by July 1999. NERC is conducting monthly readiness assessment surveys and coordinating information sharing and contingency planning activities among the member firms. The NERC activity addresses all aspects of the interconnected electric grid. The aggregated results are being reported to the DOE and other regulatory bodies in the U.S., Canada and Mexico. The Natural Gas Council, through the American Gas A s sociation, is coordinating similar processes within the gas industry, reporting to the Federal Energy Regulatory Commission (FERC). Tampa Electric and Peoples Gas System are active participants in these industry groups.
Costs The total cost of Year 2000 remediation is expected to be $9 million, which includes contracted resources, purchases and internal labor. An estimated breakdown of project costs is as follows: Tampa E l ectric - $6 million and Peoples Gas System - $3 million. Approximately 40 percent of the projected costs are attributable to testing expenses, and the remainder consists primarily of renovation
or replacement costs. Through Dec. 31, 1998, approximately $6 million had been spent, including approximately $1 million spent prior to 1998. The company expects to spend approximately $3 million in 1999 for Year 2000 remediation.
Risks The company believes the most reasonably likely worst case scenario would be the occurrence of isolated outages of limited duration for utility customers. The utilities have assessed the risk of this scenario, and believe that their contingency efforts, primarily the ability to bypass automated controls, would mitigate the effect of such a scenario.
Contingency Plans The company's contingency plan is scheduled to be completed by the middle of 1999. The contingency plan will include a team to be e s t ablished in 1999 to monitor all critical systems through significant date transitions and to promptly respond to any problems.
Forward-Looking Statements The costs of Tampa Electric Company's Year 2000 efforts and the dates on which the company believes it will complete such efforts are based upon management's best estimates, which were derived using numerous assumptions regarding future events, including the continued availability of certain resources, third-party remediation plans and other factors. There can be no assurance that these estimates will prove to be accurate, and actual results could differ materially from those currently projected. Specific factors that could cause such differences include, but are not limited to, the availability and cost of personnel trained in Year 2000 issues, the ability to identify, assess, remediate and test all relevant computer codes and embedded technology and similar uncertainties.
NON-OPERATING ITEMS:
Other Income (Expense)
Other income (expense) includes a one-time pretax charge of $7.3 million at Tampa Electric reflecting the FPSC decision denying recovery of certain coal expenses. See Utility Regulation - Cost Recovery Clauses section. The dividend requirement for Tampa Electric preferred stock, included in Other Income (expense), declined in 1997 reflecting the redemption of all outstanding preferred stock. Allowance for other funds used during construction (AFUDC) was $.1 million in 1997 and $16.5 million in 1996; no AFUDC was recorded in 1998. AFUDC is expected to be approximately $1-2 million per year over the next five years.
Interest Charges
Interest charges were $63.4 million, down 5 percent from $66.4 million in 1997 due to lower interest on a declining deferred revenue balance at Tampa Electric and lower short-term rates in 1998. Interest charges were up 16 percent in 1997, reflecting lower AFUDC on borrowed funds at Tampa Electric.
ENVIRONMENTAL COMPLIANCE:
Tampa Electric is complying with 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, controlling stack emissions and using emission allowances. In 1998, Tampa Electric made a decision to add a scrubber in order to comply with Phase II of the CAAA. The $84 million scrubber will reduce the amount of sulfur dioxide emitted by the Tampa Electric's Big Bend Units One and Two and will allow significant fuel savings at other Tampa Electric units. As a result of this project, all of the units at Big Bend Station, Tampa Electric's largest generating station, will be equipped with scrubber technology. The FPSC approved the FGD system as the most cost effective a l t e rnative for Tampa Electric to meet its CAAA compliance requirements and the recovery of prudently incurred costs through the environmental cost recovery clause. Cost recovery will not begin, however, until the FGD system is in service and Tampa Electric has applied for such recovery specifying the costs actually incurred. The U.S. Environmental Protection Agency (EPA) has commenced an investigation under the Clean Air Act of coal-fired electric power generators to determine compliance with environmental permitting requirements associated with repairs, maintenance, modifications and operations changes made to the facilities over the years. The EPA's focus is on whether new source performance standards should be applied to the changes and, accordingly, whether the best available control technology was or should have been used. Tampa Electric is one of several electric utilities that have been visited by EPA personnel and received a comprehensive request for information pursuant to Section 114 of EPA's Clean Air Act regulations. Tampa Electric is furnishing appropriate information. It believes that it has built, maintained and operated its facilities in compliance with relevant environmental permitting requirements. The timing of completion and the outcome of the EPA s investigation are uncertain. 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 material 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 are being accomplished through agreements entered into 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 increased to 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 in January 1996, reducing annual revenues by approximately $12 million. In 1995, Tampa Electric deferred $51 million of revenues under this plan. The deferred revenues accrue 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 for the capital costs incurred in 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 a ROE of 11.75 percent. Under this plan, any additional revenues were allocated as follows: *In 1996, 40 percent of any actual revenues contributing to a ROE in excess of 11.75 percent were included in 1996 revenues. The remaining 60 percent were deferred for use 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 use by the company in 1997 and 1998. *In 1997, 40 percent of any revenues that contributed to a 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 revenues that contributed to a ROE in excess of 11.75 percent up to 12.75 percent were included in revenues. The remaining 60 percent, along with all revenues contributing to a ROE in excess of 12.75 percent, including deferrals from prior years, will be refunded to customers in 1999. In 1998, Tampa Electric recognized all of the remaining deferred revenues and interest from 1995 and 1996, and based on 1998 earnings levels, expects to refund $1 million to customers in 1999, following audits for the years 1997 and 1998 and final review by the FPSC. *For 1999, 60 percent of the revenues contributing to a ROE in excess of 12 percent will be refunded to customers in 2000 following audit and review by the FPSC along with any 1999 revenues that contribute to a ROE above 12.75 percent. In 1998, Tampa Electric recorded $1.1 million in after-tax charges relating to its 1996 earnings as a result of an FPSC audit of t h a t year which involved several adjustments, including the establishment for regulatory purposes of an equity ratio cap of 58.7 percent for 1996 compared to the actual ratio for the year of 59.5 percent. Because of the return on equity thresholds in Tampa Electric's regulatory agreements described above and the potential for customer refunds in 1999 and 2000, Tampa Electric expects continuing audit scrutiny by the FPSC and active involvement of intervenors in the proceedings for determining the appropriate level of earnings for the remaining years of the stipulation and the resulting level of deferrals and/or refunds. The regulatory arrangements described above covered periods that end on Dec. 31, 1999. In the absence of any new arrangement, Tampa Electric's rates and the midpoint of its allowed rate of return on common equity (11.75 percent) 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 cannot predict whether there will be any such agreement or the potential outcome related to any other proceedings. The effective implementation of the rate stabilization strategy has resulted in residential retail rates for 1999 that are below $80
per 1,000 kwh, even as Polk Unit One was brought on line. This rate is almost 10 percent lower than 1994 rates just prior to the rate stabilization plan and comparable to rates in 1985.
Wholesale Power Sales Contracts In 1997, the FPSC ruled that costs associated with two long-term, wholesale power sales contracts should be assigned to the wholesale jurisdiction for 1997 through 1999. It further required that, for retail rate making purposes through the end of the stipulation period, the costs separated from retail to wholesale should reflect average costs rather than the lower incremental costs on which the two contracts were based. By 1998, one of these contracts had been terminated. In order to mitigate the impacts of the FPSC's ruling on the remaining contract, which expires in 2001, Tampa Electric entered into firm purchased power contracts with third parties in early 1998 to provide replacement power through 1999. As a result, Tampa Electric is no longer separating the associated generation assets from the retail jurisdiction. Because the costs under the firm purchased power c o ntracts exceeded the revenues associated with the remaining wholesale power sale agreement, Tampa Electric recorded a $9.6-million pre-tax charge in the first quarter of 1998. Tampa Electric is considering applying to the FPSC for a ruling that would provide for more favorable regulatory accounting treatment after 1999, as well as other mitigation measures.
Cost Recovery Clauses In 1998, the FPSC changed its proceedings for the recovery of fuel, purchase power and environmental costs from semi-annual to annual. In the November 1998 proceeding for calendar year 1999, the FPSC disallowed retroactively to 1992 certain quality adjustments for coal purchased from a Tampa Electric affiliate in excess of an established benchmark. This resulted in a one-time pretax charge of $7.3 million in 1998. In this same proceeding, the FPSC allowed the recovery of $4.5 million in 1999 for environmental costs, a portion of which constitutes a return on investment. These recoveries, subject to annual approval, are expected to continue in future years in declining amounts as assets depreciate.
Long Range Power Supply Planning Tampa Electric filed a Ten Year Site Plan with the FPSC in April 1998. An amended plan was filed in August 1998 as the result of greater-than-expected growth in retail load. Strong demand in 1997, followed by record energy sales throughout the summer of 1998, were evidence of this growth. This trend resulted in a projection of reserves falling below the planning criteria of a 15 percent reserve margin prior to the originally scheduled in service date of the next proposed generation addition in 2003. The revised plan includes a combustion turbine with a winter rating of 180 MW in January 2001. Plans for the addition of an already scheduled combustion turbine for 2003 remain unchanged. These additions are not subject to the FPSC's competitive bidding requirements for capacity requirements, but they are subject to its standard offer. A standard offer is a requirement of the FPSC that is made to qualifying facilities and municipal solid waste facilities for purchased power in order to offset the construction of a new unit. Construction of a new unit may be disallowed entirely if enough power is contracted. The quantity of power placed in the standard offer as well as the terms and conditions of the contract are specified by the utility and require the approval of the FPSC.
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. One such initiative, which has apparently been terminated, involved the proposed merchant power plant described below with a claimed self generation use. This is further discussed in the Wholesale Power Market section which follows. 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 1998, the FPSC approved a tariff for Tampa Electric that should assist in reducing the loss of existing at-risk load and assist in the acquisition of new load. This Commercial/ Industrial Service Rider is a load retention or economic development contract, that provides for flexible pricing to meet competitive alternatives available to existing or potential new customers.
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 for independent power producers certain regulatory barriers and required utilities to transmit power from such producers, utilities and others to wholesale customers. A significant question to be addressed in Florida is whether merchant power plants should be permitted to serve growing customer demand for electricity. Merchant plants are built on speculation without a portion or all of their capacity committed under firm purchase agreements. Tampa Electric believes that only Florida utilities or entities with contracts for firm capacity to serve the long-term needs of a Florida utility can legally be applicants under the Florida Power Plant Siting Act (PPSA). The PPSA governs the building of new generation involving steam capacity of 75 megawatts or more and requires the applicant to demonstrate that a plant is needed prior to receiving construction and operating permits. In 1997, IMC Agrico (IMCA), a retail customer of Tampa Electric and other utilities, and Duke Energy announced that they had signed a letter of intent for the construction of a natural gas-fired, combined-cycle power plant with a minimum capacity of 240 megawatts to serve load currently served by Tampa Electric and two other utilities, and the merchant wholesale function described above. Tampa Electric and others objected to the proposed project on the grounds that it involved retail transactions within defined service areas that are prohibited under existing Florida regulation. In early 1998 and prior to an FPSC-ordered evidentiary hearing to determine if the proposed project should be considered permitted self-generation or a prohibited retail sale, IMCA withdrew its petition. Duke Energy subsequently announced that it did not intend to pursue the project with IMCA. In late 1998, New Smyrna Beach and Duke Energy New Smyrna Beach Power Company Ltd. applied for 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 designated for wholesale sales to other utilities.
Tampa Electric and others intervened to oppose this proposal. On March 4, 1999, the FPSC determined that the proponents of the merchant plant are proper applicants under the PPSA and voted to approve the need for the proposed merchant plant. These decisions are expected to be appealed. The proposed plant is still subject to environmental and other regulatory approvals. If the FPSC decision is upheld or other regulatory or legislative actions are taken that 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 and energy services. 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.
Derivatives and Hedging Policy Based on policies and procedures approved by the Board of Directors, from time to time Tampa Electric Company enters into futures, swaps and option 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 Tampa Electric Company enters into futures, swaps and options contracts to limit exposure to gas price increases at the regulated natural gas utility. The benefits of these
financial arrangements are at risk only in the event of non- performance by the other party to the agreement, which the company does not anticipate. Tampa Electric Company does not use derivatives or other financial instruments for speculative purposes.
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, 1998.
Commodity Price Risk Tampa Electric and Peoples Gas System are sensitive to changes in certain commodity prices. Such changes could affect the prices they charge, their operating costs and the competitive position of their products and services. In the case of Tampa Electric, fuel costs used for generation are mostly affected by the cost of coal. Tampa Electric is able to recover the cost of fuel through retail customers' bills, but increases in fuel costs affect electric prices and therefore the competitive position of electricity against other energy sources. On the wholesale side, the ability to make sales and the margins on power sales are affected by the cost of coal to Tampa Electric, particularly as it relates to the cost of gas and oil to other power producers. In the case of Peoples Gas System, costs for purchased gas and pipeline capacity are recovered through retail customers' bills, but increases in gas costs affect total retail prices and therefore the competitive position of Peoples Gas relative to electricity, other forms of energy and other gas suppliers. 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 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Page No.
Report of Independent Accountants 29
Balance Sheets, Dec. 31, 1998 and 1997 30
Statements of Income for the years ended Dec. 31, 1998, 1997 and 1996 31
Statements of Cash Flows for the years ended Dec. 31, 1998, 1997 and 1996 32
Statements of Retained Earnings for the years ended Dec. 31, 1998, 1997 and 1996 33
Statements of Capitalization, Dec. 31, 1998 and 1997 33-35
Notes to Financial Statements 36-46
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 ACCOUNTANTS
To the Board of Directors of Tampa Electric Company
In our opinion, the accompanying balance sheets and the related statements of income, of cash flows, of retained earnings and of capitalization present fairly, in all material respects, the financial position of Tampa Electric Company, (a wholly owned subsidiary of TECO Energy, Inc.) at Dec. 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended Dec. 31, 1998, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these financial statements in accordance with generally accepted auditing standards 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. 15, 1999
BALANCE SHEETS (millions) Assets Dec. 31, 1998 1997 Property, Plant and Equipment, At Original Cost Utility plant in service Electric $3,742.6 $3,632.0 Gas 518.5 471.1 Construction work in progress 71.5 40.6 4,332.6 4,143.7 Accumulated depreciation (1,722.2) (1,595.3) 2,610.4 2,548.4 Other property 8.1 6.5 2,618.5 2,554.9 Current Assets Cash and cash equivalents .8 2.8 Receivables, less allowance for uncollectibles 142.8 161.4 Inventories, at average cost Fuel 87.3 69.5 Materials and supplies 45.5 45.6 Prepayments 8.4 7.3 284.8 286.6 Deferred Debits Unamortized debt expense 16.1 17.5 Deferred income taxes 116.1 112.2 Regulatory asset-tax related 39.0 41.8 Other 72.0 85.9 243.2 257.4 $3,146.5 $3,098.9
Liabilities and Capital Capital Common stock $1,026.1 $ 972.1 Retained earnings 288.5 289.6 1,314.6 1,261.7 Preferred stock, redemption not required -- -- Long-term debt, less amount due within one year 774.5 727.1 2,089.1 1,988.8 Current Liabilities Long-term debt due within one year 4.6 4.1 Notes payable 79.7 219.1 Accounts payable 189.1 118.4 Customer deposits 77.5 77.3 Interest accrued 8.8 18.7 Taxes accrued 8.8 8.5 368.5 446.1 Deferred Credits Deferred income taxes 447.6 415.6 Investment tax credits 45.1 49.7 Regulatory liability-tax related 73.0 77.0 Other 123.2 121.7 688.9 664.0 $3,146.5 $3,098.9
The accompanying notes are an integral part of the financial statements.
STATEMENTS OF INCOME (millions)
Year ended Dec. 31, 1998 1997 1996
Operating Revenues Electric $1,234.6 $1,189.2 $1,112.9 Gas 252.8 249.5 258.6 1,487.4 1,438.7 1,371.5 Operating Expenses Operation Fuel 366.5 373.4 383.1 Purchased power 84.7 67.7 49.0 Natural gas sold 115.4 119.6 130.1 Other 221.2 215.7 216.9 Maintenance 98.8 83.4 70.3 Non-recurring charge 9.6 -- -- Depreciation 167.2 161.2 137.4 Taxes-Federal and state income 86.3 87.5 79.9 Taxes-Other than income 118.1 112.6 108.7 1,267.8 1,221.1 1,175.4 Operating Income 219.6 217.6 196.1
Other Income (Expense) Allowance for other funds used during construction -- .1 16.5 Other expense, net (9.8) (2.7) (.1) (9.8) (2.6) 16.4 Income before interest charges 209.8 215.0 212.5
Interest Charges Interest on long-term debt 50.4 50.7 46.5 Other interest 13.0 15.8 16.9 Allowance for borrowed funds used during construction -- (.1) (6.4) 63.4 66.4 57.0 Net Income 146.4 148.6 155.5 Preferred dividend requirements -- .5 1.8 Balance Applicable to Common Stock $ 146.4 $ 148.1 $ 153.7
The accompanying notes are an integral part of the financial statements.
STATEMENTS OF CASH FLOWS (millions) Year ended Dec. 31, 1998 1997 1996 Cash Flows from Operating Activities Net income $146.4 $148.6 $ 155.5 Adjustments to reconcile net income to net cash Depreciation 167.2 161.2 137.4 Deferred income taxes 28.5 21.1 9.4 Investment tax credits, net (4.6) (4.7) (4.7) Allowance for funds used during construction -- (.2) (22.9) Deferred clause revenues (expenses) 17.4 2.7 7.4 Deferred revenue (38.3) (30.5) 34.2 Refund to customers -- (19.8) (6.0) Non-recurring charges 16.9 -- -- Receivables, less allowance for uncollectibles 18.6 2.7 (10.0) Inventories (17.7) (15.2) 10.8 Taxes accrued .3 (3.5) (8.4) Accounts payable 70.7 (15.0) (15.9) Other 10.1 (23.3) 9.3 415.5 224.1 296.1 Cash Flows from Investing Activities Capital expenditures (232.1) (155.3) (229.3) Allowance for funds used during construction -- .2 22.9 (232.1) (155.1) (206.4) Cash Flows from Financing Activities Proceeds from contributed capital from parent 54.0 5.0 83.0 Proceeds from long-term debt 51.2 -- 78.1 Repayment of long-term debt (3.7) (16.7) (26.3) Net borrowings (payments) under credit lines -- (10.0) -- Net increase (decrease) in short-term debt (139.4) 118.9 (45.9) Redemption of preferred stock -- (20.4) (35.5) Dividends (147.5) (146.5) (147.1) (185.4) (69.7) (93.7) Net decrease in cash and cash equivalents (2.0) (.7) (4.0) Cash and cash equivalents at beginning of year 2.8 3.5 7.5 Cash and cash equivalents at end of year $ .8 $ 2.8 $ 3.5
Supplemental Disclosure of Cash Flow Information
Cash paid during the year for: Interest $ 58.1 $ 57.1 $ 48.6 Income taxes $ 40.4 $ 85.3 $ 91.1
The accompanying notes are an integral part of the financial statements.
STATEMENTS OF RETAINED EARNINGS (millions)
Year ended Dec. 31, 1998 1997 1996 Balance, Beginning of Year $289.6 $285.7 $277.3 Add-Net income 146.4 148.6 155.5 West Florida Gas Merger -- 2.3 -- 436.0 436.6 432.8 Deduct- Cash dividends on capital stock Preferred -- .6 2.1 Common 147.5 145.9 145.0 Other - adjustment -- .5 -- 147.5 147.0 147.1 Balance, End of Year $288.5 $289.6 $285.7
The accompanying notes are an integral part of the financial statements.
STATEMENTS OF CAPITALIZATION
Capital Stock Outstanding Cash Dividends Dec.31, 1998 Paid in 1998(1) Current Redemption Per Price Shares Amount(2) Share Amount(2) Common stock-Without par value 25 million shares authorized N/A 10 $1,026.1 N/A $147.5
Preferred Stock-$100 Par Value 1.5 million shares authorized, none outstanding. Preferred Stock - no Par 2.5 million shares authorized, none outstanding. Preference Stock - no Par 2.5 million shares authorized, none outstanding. _________________ (1) Quarterly dividends paid on Feb. 15, May 15, Aug. 15 and Nov. 15. (2) Millions.
STATEMENTS OF CAPITALIZATION (continued)
Long-Term Debt Outstanding at Dec. 31, Due 1998 1997
Tampa Electric First mortgage bonds (issuable in series): 7 3/4% 2022 $ 75.0 $ 75.0 5 3/4% 2000 80.0 80.0 6 1/8% 2003 75.0 75.0 Installment contracts payable(2) 5 3/4% 2007 23.5 23.8 7 7/8% Refunding bonds(3) 2021 25.0 25.0 8% Refunding bonds(3) 2022 100.0 100.0 6 1/4% Refunding bonds(4) 2034 86.0 86.0 5.85% 2030 75.0 75.0 Variable rate: 3.06% for 1998 and 3.55% for 1997(1) 2025 51.6 51.6 Variable rate: 3.17% for 1998 and 3.45% for 1997(1) 2018 54.2 54.2 Variable rate: 3.39% for 1998 and 3.78% for 1997(1) 2020 20.0 20.0 Medium-term note payable: 5.11% (1)(5) 2001 38.0 -- 703.3 665.6 Peoples Gas System Senior Notes(6) 10.35% 2007 6.8 7.4 10.33% 2008 8.6 9.2 10.3% 2009 9.2 9.4 9.93% 2010 9.4 9.6 8.0% 2012 32.0 33.5 Medium-term note payable: 5.11% (1)(5) 2001 12.0 -- 78.0 69.1
Unamortized debt premium (discount), net (2.2) (3.5) 779.1 731.2 Less amount due within one year(7) 4.6 4.1 Total long-term debt $ 774.5 $ 727.1
(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 1998, $.8 million may be satisfied by the substitution of property in lieu of cash payments.
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 2000, 2001, 2002 and 2003 are $84.8 million, $55.2 million, $6.0 million, and $81.5 million, respectively. Of these amounts $.8 million per year for 2000 through 2003 may be satisfied by the substitution of property in lieu of cash payments. At Dec. 31, 1998, total long-term debt had a carrying amount of $774.5 million and an estimated fair market value of $878.7 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 financial statements.
NOTES TO 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 w i th 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 and 1996. Revenues are recognized as allowed in 1997 and 1998 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 recovery of prudent costs incurred plus a reasonable return on invested capital. The use of estimates is inherent in the preparation of financial s t a t e ments 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 debits. 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 1998, 1997 and 1996, $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 Counsel (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 allows the full recovery of the capital costs incurred in the construction of the Polk Power Station project, and calls 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 4.1% for 1998 and 4.0% for 1997 and 1996. 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 it, 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 1998 or 1997.
Reporting Comprehensive Income In 1997, the Financial Accounting Standards Board issued FAS 130, Reporting Comprehensive Income, effective for fiscal years beginning after Dec. 15, 1997. The new 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, 1998, 1997 and 1996.
Deferred Income Taxes The liability method is utilized in the measurement of deferred income taxes. Under the liability method, the temporary differences b e tween 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 e s tablishment of a corresponding net 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.
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 1998, 1997 and 1996. Total AFUDC for 1997 and 1996 was $0.2 million and $22.9 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.
Hedges - Gas Prices Peoples Gas System enters into natural gas options contracts, from time to time, to limit its exposure to gas price increases. Tampa Electric Company does not use derivatives or other financial products for speculative purposes.
Accounting for Derivative Instruments and Hedging In 1998, the Financial Accounting Standards Board issued FAS 133, Accounting for Derivative Instruments and Hedging, effective for fiscal years beginning after June 15, 1999. The new standard requires that an entity 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 net income, depending on the types of those instruments. Tampa Electric Company does not use derivatives or other financial products for speculative purposes. The company has not yet determined to what extent the standard will impact its financial statements.
Mergers In June 1997, TECO Energy, Inc. completed its merger with Lykes E n e rgy, 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 and Restatements Certain prior year amounts were reclassified or restated to conform with current year presentation.
B. Common Stock
The company is a wholly owned subsidiary of TECO Energy, Inc.
Common Stock Issue (thousands) Shares Amount Expense Total
Balance Dec. 31, 1995 10 $ 879.5 $(1.4) $ 878.1 Contributed capital from parent - 83.0 -- 83.0 Costs associated with Preferred Stock retirements (1) -- 0.6 0.6 Balance Dec. 31, 1996 10 962.5 (0.8) 961.7 Contributed capital from parent - 5.0 -- 5.0 Costs associated with Preferred Stock retirements (2) -- 0.1 0.1 West Florida Natural Gas merger - 5.3 -- 5.3 Balance Dec. 31, 1997 10 972.8 (0.7) 972.1 Contributed capital from parent - 54.0 -- 54.0 Balance Dec. 31, 1998 10 $1,026.8 $(0.7) $1,026.1
(1) In April 1996, the Tampa Electric retired $35 million aggregate par value of 8.00% Series E and 7.44% series F preferred stock. In connection with this retirement, $.6 million of associated issuance costs were recognized. (2) 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, 1998, 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 earnings. 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 70 percent of plan assets were invested in common stocks and 30 percent in fixed income investments at Dec. 31, 1998. 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.
Components of Net Pension Expense (millions) 1998 1997 1996 Service cost (benefits earned during the period) $11.2 $ 9.6 $ 9.9 Interest cost on projected benefit obligations 24.8 23.6 22.2 Less: Expected return on plan assets (31.5) (28.4) (26.4) Amortization of: Unrecognized transition asset (1.1) (1.2) (1.2) Prior service cost 0.9 0.9 0.8 Actuarial (gain) loss -- (0.3) (0.1) Net pension expense 4.3 4.2 5.2 Special termination benefit charge 0.7 -- -- Curtailment charge (0.8) -- (1.0) Net pension expense recognized in TECO Energy's Consolidated Statements of Income (1) $ 4.2 $ 4.2 $ 4.2
(1) Tampa Electric Company's portion was $2.1 million, $2.6 million and $3.5 million for 1998, 1997 and 1996, respectively.
Reconciliation of the Funded Status of the Retirement Plan and the Accrued Pension Prepayment/(Liability) (millions) Dec. 31, Dec. 31, 1998 1997
Projected benefit obligation, beginning of year $344.7 $262.2 Change in benefit obligation due to: Service cost 11.2 9.6 Interest cost 24.8 23.6 Actuarial (gain) loss 22.4 22.1 Acquisitions -- 47.6 Curtailments (1.1) -- Special termination benefits 0.7 -- Gross benefits paid (19.0) (20.4) Projected benefit obligation, end of year 383.7 344.7 Fair value of plan assets, beginning of year 414.8 320.5 Change in plan assets due to: Actual return on plan assets 72.2 65.8 Employer contributions 0.7 -- Acquisitions -- 48.9 Gross benefits paid (19.0) (20.4) Fair value of plan assets, end of year 468.7 414.8 Funded status, end of year 85.0 70.1 Unrecognized net actuarial gain (102.9) (83.7) Unrecognized prior service cost 10.7 11.0 Unrecognized net transition asset (7.0) (8.1) Accrued pension liability (2) $(14.2) $(10.7)
(2) Tampa Electric Company's portion was $12.1 million and $10.6 million at Dec. 31, 1998 and 1997, respectively.
Assumptions Used in Determining Actuarial Valuations 1998 1997 Discount rate to determine projected benefit obligation 6.75% 7.25% Rates of increase in compensation levels 3.3-5.3% 3.3-5.3% Plan asset growth rate through time 9% 9%
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.
Components of Postretirement Benefit Cost (millions) 1998 1997 1996 Service cost (benefits earned during the period) $1.5 $1.3 $1.4 Interest cost on projected benefit obligations 4.2 4.4 4.6 Amortization of transition obligation (straight line over 20 years) 2.1 2.1 2.1 Amortization of actuarial loss/(gain) (0.1) (0.1) 0.2 Net periodic Postretirement benefit expense $7.7 $7.7 $8.3
Reconciliation of the Funded Status of the Postretirement Benefit Plan and the Accrued Liability (millions) Dec. 31, Dec. 31, 1998 1997 Accumulated postretirement benefit obligation, beginning of year $ 61.7 $ 62.2 Change in benefit obligation due to: Service cost 1.5 1.3 Interest cost 4.2 4.4 Plan participants' contributions 0.1 0.2 Actuarial (gain) loss 0.3 (2.5) Gross benefits paid (3.7) (3.9) Accumulated postretirement benefit obligation, end of year $ 64.1 $ 61.7
Funded status, end of year $(64.1) $(61.7) Unrecognized net loss from past experience 5.3 4.9 Unrecognized transition obligation 29.5 31.6 Liability for accrued postretirement benefit $(29.3) $(25.2)
Assumptions Used in Determining Actuarial Valuations 1998 1997 Discount rate to determine projected benefit obligation 6.75% 7.25%
The assumed health care cost trend rate for medical costs prior to age 65 was 8.75% in 1998 and decreases to 5.75% in 2002 and thereafter. The assumed health care cost trend rate for medical costs after age 65 was 6.75% in 1998 and decreases to 5.75% in 2002 and thereafter. A 1-percent increase in the medical trend rates would produce a 9-percent ($0.5 million) increase in the aggregate service and interest cost for 1998 and an 8-percent($4.9 million) increase in the accumulated postretirement benefit obligation as of Dec. 31, 1998. A 1-percent decrease in the medical trend rates would produce a 7-percent ($0.4 million) decrease in the aggregate service and interest cost for 1998 and a 7-percent($4.2 million) decrease in the accumulated postretirement benefit obligation as of Dec. 31, 1998.
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:
(millions) Federal State Total Currently payable $ 52.8 $ 9.3 $ 62.1 Deferred 24.7 3.8 28.5 Amortization of investment tax credits (4.6) - (4.6) Total income tax expense $ 72.9 $ 13.1 86.0 Included in other income, net (0.3) Included in operating expenses $ 86.3
Currently payable $ 62.9 $ 7.1 $ 70.0 Deferred 15.0 6.1 21.1 Amortization of investment tax credits (4.7) -- (4.7) Total income tax expense $ 73.2 $ 13.2 86.4 Included in other income, net (1.1) Included in operating expenses $ 87.5
Currently payable $ 63.9 $ 11.1 $ 75.0 Deferred 8.3 1.1 9.4 Amortization of investment tax credits (4.7) - (4.7) Total income tax expense $ 67.5 $ 12.2 79.7 Included in other income, net (0.2) Included in operating expenses $ 79.9
D e f erred 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:
Dec. 31, Dec. 31, (millions) 1998 1997 Deferred tax assets(1) Property related $ 90.1 $ 87.4 Leases 4.8 5.2 Insurance reserves 10.7 9.2 Early capacity payments 2.2 2.2 Other 8.3 8.2 Total deferred income tax assets 116.1 112.2 Deferred income tax liabilities(1) Property related (475.9) (450.9) Other 28.3 35.3 Total deferred income tax liabilities (447.6) (415.6) Accumulated deferred income taxes $(331.5) $(303.4) _________________ (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:
(millions) 1998 1997 1996 Net income $146.4 $148.6 $155.5 Total income tax provision 86.0 86.4 79.7 Income before income taxes $232.4 $235.0 $235.2
Income taxes on above at federal statutory rate of 35% $ 81.3 $ 82.3 $ 82.3 Increase (decrease) due to State income tax, net of federal income tax 8.5 8.6 8.0 Amortization of investment tax credits (4.6) (4.7) (4.7) Equity portion of AFUDC -- -- (5.8) Other 0.8 0.2 (0.1) Total income tax provision $ 86.0 $ 86.4 $ 79.7 Provision for income taxes as a percent of income before income taxes 37.0% 36.7% 33.9%
G. Short-term Debt
Notes payable consisted primarily of commercial paper with weighted average interest rates of 5.18% and 5.72% at Dec. 31, 1998 a n d 1997, 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, 1998 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:
1998 1997 1996 Fuel and interchange related, net $149.6 $154.6 $154.9 Administrative and general, net $ 13.5 $ 9.5 $ 10.6
Amounts due from or to affiliates of the company at year-end are as follows:
1998 1997 Accounts receivable $ 3.6 $ 7.7 Accounts payable $ 19.2 $ 20.1
Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.
I. Non-Recurring Charges
In 1998, the company recognized one-time charges totaling $16.9 million, pretax ($10.3 million after-tax). Of the $16.9 million pretax charges, $9.6 million ($5.9 million, after-tax) was recorded in operating expenses a non-recurring charge and $7.3 million ($4.4 million, after-tax) was recorded in other expense. 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 uneconomical. One contract was terminated in 1997. As to the other contract, which expires in 2001, Tampa Electric has 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 e x c eeds the revenues expected through 1999. To reflect this difference, Tampa Electric recorded a $5.9-million after-tax charge in 1998. Tampa Electric also recorded a $4.4-million, after-tax charge in 1998 for a recent FPSC denial of the recovery of certain BTU coal quality adjustments for coal purchase since 1993. This was recorded as other expense on the income statement.
J. Commitments and Contingencies
Tampa Electric's capital expenditures are estimated to be $142 million in 1999 and $506 million for 2000 through 2003 for equipment and facilities to meet customer growth and generation reliability programs. Additionally, Tampa Electric is also expecting to spend $61 million in 1999 and $6 million during 2000-2003 to complete the scrubber project at Big Bend Power Station and is forecasting $19 million in 1999 and $194 million during 2000-2003 to construct additional generation expansion. At the end of 1998, Tampa Electric had outstanding commitments of about $68 million to complete the scrubber and $44 million to construct additional generation expansion. Peoples Gas System s capital expenditures are estimated to be $75 million for 1999 and $208 million for 2000 through 2003 for infrastructure expansion to grow the customer base and normal asset replacement. At the end of 1998, Peoples Gas System had outstanding commitments of $8 million related to its Southwest Florida expansion.
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 537,000 customers in West Central Florida. Its Peoples Gas System division is engaged in the purchase, distribution and marketing of natural gas for almost 240,000 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 $86.3 million, $87.5 million and $79.9 million in 1998, 1997 and 1996, respectively. (2) Revenues from sales to affiliates were $23.2 million, $22.2 million and $20.5 million in 1998, 1997 and 1996, respectively. (3) Revenues shown in 1998 and 1997 include the recognition of previously deferred revenue of $38.3 million and $30.5 million, respectively. Revenues shown in 1996 are after the revenues deferral of $34.2 million. (4) Operating income excludes a non-recurring pretax charge of $9.6 million in 1998. See Note I.
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
During the period from Jan. 1, 1997 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 28. 2. Financial Statement Schedules - See index on page 28. 3. Exhibits *3.1 A r ticles of Incorporation (Exhibit 3.1 to Registration Statement No. 2-70653). *3.2 Bylaws, as amended, effective April 16, 1997 (Exhibit 3, Form 10-Q for the quarter ended June 30, 1997 of Tampa Electric Company). *4.1 Indenture of Mortgage among Tampa Electric Company, State Street Trust Company and First Savings & Trust Company of Tampa, dated as of Aug. 1, 1946 (Exhibit 7-A to Registration Statement No. 2-6693). *4.2 Thirteenth Supplemental Indenture, dated as of Jan. 1, 1974, to Exhibit 4.1 (Exhibit 2-g-l, Registration Statement No. 2-51204). *4.3 Sixteenth Supplemental Indenture, dated as of Oct. 30, 1992, to Exhibit 4.1 (Exhibit 4.1, Form 10-Q for the quarter ended Sept. 30, 1992 of Tampa Electric Company). *4.4 Eighteenth Supplemental Indenture, dated as of May 1, 1993, to Exhibit 4.1 (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 1993). *4.5 Installment Purchase and Security Contract between t h e Hillsborough County Industrial Development Authority and Tampa Electric Company, dated as of March 1, 1972 (Exhibit 4.9, Form 10-K for 1986 of Tampa Electric Company). *4.6 First Supplemental Installment Purchase and Security Contract, dated as of Dec. 1, 1974 (Exhibit 4.10, Form 10-K for 1986 of Tampa Electric Company). *4.7 Third Supplemental Installment Purchase Contract, dated as of May 1, 1976 (Exhibit 4.12, Form 10-K for 1986 of Tampa Electric Company). *4.8 Installment Purchase Contract between the Hillsborough County Industrial Development Authority and Tampa Electric Company, dated as of Aug. 1, 1981 (Exhibit 4.13, Form 10-K for 1986 of Tampa Electric Company). *4.9 Amendment to Exhibit A of Installment Purchase Contract, dated as of April 7, 1983 (Exhibit 4.14, Form 10-K for 1989 of Tampa Electric Company). *4.10 Second Supplemental Installment Purchase Contract, dated as of June 1, 1983 (Exhibit 4.11, Form 10-K for 1994 of Tampa Electric Company). *4.11 Third Supplemental Installment Purchase Contract,
dated as of Aug. 1, 1989 (Exhibit 4.16, Form 10-K for 1989 of Tampa Electric Company). *4.12 Installment Purchase Contract between the Hillsborough County Industrial Development Authority and Tampa Electric Company, dated as of Jan. 31, 1984 (Exhibit 4.13, Form 10-K for 1993 of Tampa Electric Company). *4.13 First Supplemental Installment Purchase Contract, dated as of Aug. 2, 1984 (Exhibit 4.14, Form 10-K for 1994 of Tampa Electric Company). *4.14 Second Supplemental Installment Purchase Contract, dated as of July 1, 1993 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 1993). *4.15 Loan and Trust Agreement among the Hillsborough C o u nty Industrial Development Authority, Tampa Electric Company and NCNB National Bank of Florida, dated as of Sept. 24, 1990 (Exhibit 4.1, Form 10-Q for the quarter ended Sept. 30, 1990 of Tampa Electric Company). *4.16 Loan and Trust Agreement, dated as of Oct. 26, 1992 among the Hillsborough County Industrial Development Authority, Tampa Electric Company and NationsBank of Florida, N.A., as trustee (Exhibit 4.2, Form 10-Q for the quarter ended Sept. 30, 1992 of Tampa Electric Company). *4.17 Loan and Trust Agreement, dated as of June 23, 1993, among the Hillsborough County Industrial Development Authority, Tampa Electric Company and NationsBank of Florida, N.A., as trustee (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 1993 of Tampa Electric Company). *4.18 Loan and Trust Agreement, dated as of Dec. 1, 1996, a m o n g the Polk County Industrial Development Authority, Tampa Electric Company and the Bank of New York, as trustee (Exhibit 4.18, Form 10-K for 1996 of Tampa Electric Company). *4.19 First Supplemental Indenture dated as of July 15, 1998 between Tampa Electric Company and The Bank of New York, as trustee (Exhibit 4.1, Form 8-K dated July 28, 1998 of Tampa Electric Company). *10.1 1980 Stock Option and Appreciation Rights Plan, as amended on July 18, 1989 (Exhibit 28.1, Form 10-Q for the quarter ended June 30, 1989 of TECO Energy, Inc.). *10.2 TECO Energy Group Supplemental Executive Retirement Plan, as amended and restated as of Oct. 16, 1996 (Exhibit 10.3, Form 10-K for 1996 of Tampa Electric Company). *10.3 TECO Energy Group Supplemental Retirement Benefits Trust Agreement, as amended and restated as of Jan. 15, 1997 (Exhibit 10.4, Form 10-K for 1996 of Tampa Electric Company). 10.4 Annual Incentive Compensation Plan for TECO Energy and subsidiaries, as revised Jan. 20, 1999. *10.5 TECO Energy, Inc. Group Supplemental Disability Income Plan, dated as of March 20, 1989 (Exhibit 10.19, Form 10-K for 1988 of Tampa Electric Company). *10.6 Forms of Severance Agreements between TECO Energy, Inc. and certain senior executives, as amended and
restated as of July 15, 1998 (Exhibit 10.1, Form 10-Q for the quarter ended Sept. 30, 1998 of Tampa Electric Company). *10.7 TECO Energy, Inc. 1991 Director Stock Option Plan as amended on Jan. 21, 1992 (Exhibit 10.20, Form 10-K for 1991 of Tampa Electric Company). *10.8 Supplemental Executive Retirement Plan for R.H. Kessel, as amended and restated as of Jan. 15, 1997 (Exhibit 10.10, Form 10-K for 1996 of Tampa Electric Company). *10.9 Supplemental Executive Retirement Plan for H.L. Culbreath, as amended on April 27, 1989 (Exhibit 10.14, Form 10-K for 1989 of TECO Energy, Inc.). *10.10 Supplemental Executive Retirement Plan for A.D. Oak, as amended and restated effective as of Oct. 16, 1996 (Exhibit 10.12, Form 10-K for 1996 of Tampa Electric Company). *10.11 Supplemental Executive Retirement Plan for G.F. Anderson, as amended and restated effective as of Oct. 16, 1996 (Exhibit 10.15, Form 10-K for 1996 of Tampa Electric Company). *10.12 TECO Energy Directors' Deferred Compensation Plan, as amended and restated effective April 1, 1994 (Exhibit 10.1, Form 10-Q for the quarter ended March 31, 1994 of Tampa Electric Company). 10.13 TECO Energy Group Retirement Savings Excess Benefit Plan, as amended and restated effective as of July 15, 1998. *10.14 Severance Agreement between TECO Energy, Inc. and H. L. Culbreath, dated as of April 28, 1989 (Exhibit 10.24, Form 10-K for 1989 of TECO Energy, Inc.). *10.15 Supplemental Executive Retirement Plan for R.A. Dunn, as amended and restated effective as of Jan. 15, 1997 (Exhibit 10.20, Form 10-K for the 1996 of Tampa Electric Company). *10.16 Form of Nonstatutory Stock Option under the TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 1996 of Tampa Electric Company). *10.17 Form of Amendment to Nonstatutory Stock Option, dated as of July 15, 1998, under the TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit 10.3, Form 10-Q for the quarter ended Sept. 30, 1998 of Tampa Electric Company). *10.18 Form of Restricted Stock Agreement between TECO Energy, Inc. And certain executives under the TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 1998 of Tampa Electric Company). *10.19 Form of Amendment to Restricted Stock Agreements, dated as of July 15, 1998, between TECO Energy, Inc. and certain senior executives under the TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit 10.2, Form 10-Q for the quarter ended Sept. 30, 1998 of Tampa Electric Company). *10.20 Form of Restricted Stock Agreement between TECO Energy, Inc. and G. F. Anderson under the TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 1998
of Tampa Electric Company). *10.21 TECO Energy, Inc. 1997 Director Equity Plan (Exhibit 10.1, Form 8-K dated April 16, 1997 of Tampa Electric Company). *10.22 Form of Nonstatutory Stock Option under the TECO Energy, Inc. 1997 Director Equity Plan (Exhibit 10, Form 10-Q for the quarter ended June 30, 1997 of Tampa Electric Company). 12. Ratio of earnings to fixed charges. 23. Consent of Independent Accountants. 24.1 Power of Attorney. 24.2 Certified copy of resolution authorizing Power of Attorney. 27. Financial Data Schedule (EDGAR filing only). _____________ * 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 10.22 above are management contracts or compensatory plans or arrangements in which executive officers or directors of TECO Energy, Inc. and its subsidiaries participate.
(b) The registrant did not file any Current Reports on Form 8-K during the last quarter of 1998.
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 30th day of March, 1999.
TAMPA ELECTRIC COMPANY
By G. F. Anderson* G. F. Anderson, Chairman of the Board 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 30, 1999:
Signature Title
G. F. ANDERSON* Chairman of the Board, G. F. ANDERSON Director and Chief Executive Officer (Principal Executive Officer)
/S/G. L. GILLETTE Vice President-Finance G. L. GILLETTE and Chief Financial Officer (Principal Financial Officer)
W. L. GRIFFIN* Vice President-Controller W. L. GRIFFIN (Principal Accounting Officer)
C. D. AUSLEY* Director C. D. AUSLEY
S. L. BALDWIN* Director S. L. BALDWIN
H. L. CULBREATH* Director H. L. CULBREATH
J. L. FERMAN, JR.* Director J. L. FERMAN, JR.
E. L. FLOM* Director E. L. FLOM
H. R. GUILD, JR.* Director H. R. GUILD, JR.
T. L. RANKIN* Director T. L. RANKIN
R. L. RYAN* Director R. L. RYAN
W. P. SOVEY* Director W. P. SOVEY
J. T. TOUCHTON* Director J. T. TOUCHTON
J. A. URQUHART* Director J. A. URQUHART
J. O. WELCH, JR.* Director J. O. WELCH, JR.
*By: /s/ G. L. GILLETTE G. L. GILLETTE, Attorney-in-fact
INDEX TO EXHIBITS Exhibit Page No. Description No.
3.1 Articles of Incorporation (Exhibit 3.1 to * Registration Statement No. 2-70653). 3.2 Bylaws, as amended, effective April 16, 1997 * (Exhibit 3, Form 10-Q for the quarter ended June 30, 1997 of Tampa Electric Company). 4.1 Indenture of Mortgage among Tampa Electric * Company, State Street Trust Company and First Savings & Trust Company of Tampa, dated as of Aug. 1, 1946 (Exhibit 7-A to Registration Statement No. 2-6693). 4.2 Thirteenth Supplemental Indenture, dated as of * Jan. 1, 1974, to Exhibit 4.1 (Exhibit 2-g-l, Registration Statement No. 2-51204). 4.3 Sixteenth Supplemental Indenture, dated as of * Oct. 30, 1992, to Exhibit 4.1 (Exhibit 4.1, Form 10-Q for the quarter ended Sept. 30, 1992 of Tampa Electric Company). 4.4 Eighteenth Supplemental Indenture, dated as of May 1, * 1993, to Exhibit 4.1 (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 1993). 4.5 Installment Purchase and Security Contract * between and the Hillsborough County Industrial Development Authority and Tampa Electric Company, dated as of March 1, 1972 (Exhibit 4.9, Form 10-K for 1986 of Tampa Electric Company). 4.6 First Supplemental Installment Purchase and * Security Contract, dated as of Dec. 1, 1974 (Exhibit 4.10, Form 10-K for 1986 of Tampa Electric Company). 4.7 Third Supplemental Installment Purchase Contract, * dated as of May 1, 1976 (Exhibit 4.12, Form 10-K for 1986 of Tampa Electric Company). 4.8 Installment Purchase Contract between the * Hillsborough County Industrial Development Authority and Tampa Electric Company, dated as of Aug. 1, 1981 (Exhibit 4.13, Form 10-K for 1986 of Tampa Electric Company). 4.9 Amendment to Exhibit A of Installment Purchase * Contract, dated as of April 7, 1983 (Exhibit 4.14, Form 10-K for 1989 of Tampa Electric Company). 4.10 Second Supplemental Installment Purchase Contract, * dated as of June 1, 1983 (Exhibit 4.11, Form 10-K for 1994 of Tampa Electric Company). 4.11 Third Supplemental Installment Purchase Contract, * dated as of Aug. 1, 1989 (Exhibit 4.16, Form 10-K for 1989 of Tampa Electric Company). 4.12 Installment Purchase Contract between the * Hillsborough County Industrial Development Authority and Tampa Electric Company, dated as of Jan. 31, 1984 (Exhibit 4.13, Form 10-K for 1993 of Tampa Electric Company). 4.13 First Supplemental Installment Purchase Contract, * dated as of Aug. 2, 1984 (Exhibit 4.14, Form 10-K for 1994 of Tampa Electric Company).
4.14 Second Supplemental Installment Purchase Contract, * dated as of July 1, 1993 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 1993). 4.15 Loan and Trust Agreement among the Hillsborough * County Industrial Development Authority, Tampa Electric Company and NCNB National Bank of Florida, dated as of Sept. 24, 1990 (Exhibit 4.1, Form 10-Q for the quarter ended Sept. 30, 1990 of Tampa Electric Company). 4.16 Loan and Trust Agreement, dated as of * Oct. 26, 1992 among the Hillsborough County Industrial Development Authority, Tampa Electric Company and NationsBank of Florida, N.A., as trustee (Exhibit 4.2, Form 10-Q for the quarter ended Sept. 30, 1992 of Tampa Electric Company). 4.17 Loan and Trust Agreement, dated as of June 23, * 1993, among the Hillsborough County Industrial D e velopment Authority, Tampa Electric Company and NationsBank of Florida, N.A., as trustee (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 1993 of Tampa Electric Company). 4.18 Loan and Trust Agreement, dated as of Dec. 1, 1996, * among the Polk County Industrial Development Authority, Tampa Electric Company and the Bank of New York, as trustee (Exhibit 4.18, Form 10-K for 1996 of Tampa Electric Company). 4.19 First Supplemental Indenture dated as of July 15, 1998 * between Tampa Electric Company and The Bank of New York, as trustee (Exhibit 4.1, Form 8-K dated July 28, 1998 of Tampa Electric Company). 10.1 1980 Stock Option and Appreciation Rights Plan, * as amended on July 18, 1989 (Exhibit 28.1, Form 10-Q for the quarter ended June 30, 1989 of TECO Energy, Inc.). 10.2 TECO Energy Group Supplemental Executive Retirement * Plan, as amended and restated as of Oct. 16, 1996 (Exhibit 10.3, Form 10-K for 1996 of Tampa Electric Company). 10.3 TECO Energy Group Supplemental Retirement Benefits * Trust Agreement as amended and restated as of Jan. 15, 1997 (Exhibit 10.4, Form 10-K for 1996 of Tampa Electric Company). 10.4 Annual Incentive Compensation Plan for TECO Energy 57 and subsidiaries, revised Jan. 20, 1999. 10.5 TECO Energy, Inc. Group Supplemental Disability * Income Plan, dated as of March 20, 1989 (Exhibit 10.19, Form 10-K for 1988 of Tampa Electric Company). 10.6 Forms of Severance Agreements between TECO Energy, * Inc. and certain senior executives, as amended and restated as of July 15, 1998 (Exhibit 10.1, Form 10-Q for the quarter ended Sept. 30, 1998 of Tampa Electric Company). 10.7 TECO Energy, Inc. 1991 Director Stock Option Plan * as amended on Jan. 21, 1992 (Exhibit 10.20, Form 10-K for 1991 of Tampa Electric Company). 10.8 Supplemental Executive Retirement Plan for * R.H. Kessel, as amended and restated as of Jan. 15, 1997 (Exhibit 10.10, Form 10-K for 1996 of Tampa Electric Company).
10.9 Supplemental Executive Retirement Plan for * H.L. Culbreath, as amended on April 27, 1989 (Exhibit 10.14, Form 10-K for 1989 of TECO Energy, Inc.). 10.10 Supplemental Executive Retirement Plan for * A.D. Oak, as amended and restated effective as of Oct. 16, 1996 (Exhibit 10.12, Form 10-K for 1996 of Tampa Electric Company). 10.11 Supplemental Executive Retirement Plan for * G.F. Anderson, as amended and restated effective as of Oct. 16, 1996 (Exhibit 10.15, Form 10-K for 1996 of Tampa Electric Company). 10.12 TECO Energy Directors' Deferred Compensation Plan, * as amended and restated effective April 1, 1994 (Exhibit 10.1, Form 10-Q for the quarter ended March 31, 1994 of Tampa Electric Company). 10.13 TECO Energy Group Retirement Savings Excess Benefit 61 Plan, as amended and restated effective as of July 15, 1998. 10.14 Severance Agreement between TECO Energy, Inc. and * H.L. Culbreath, dated as of April 28, 1989 (Exhibit 10.24, Form 10-K for 1989 of TECO Energy, Inc.). 10.15 Supplemental Executive Retirement Plan for R.A. Dunn, * as amended and restated as of Jan. 15, 1997 (Exhibit 10.20, Form 10-K for 1996 of Tampa Electric Company). 10.16 Form of Nonstatutory Stock Option under the TECO Energy, * Inc. 1996 Equity Incentive Plan (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 1996 of Tampa Electric Company). 10.17 Form of Amendment to Nonstatutory Stock Option, dated * as of July 15, 1998, under the TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit 10.3, Form 10-Q for the quarter ended Sept. 30, 1998 of Tampa Electric Company). 10.18 Form of Restricted Stock Agreement between TECO Energy, * Inc. And certain executives under the TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 1998 of Tampa Electric Company). 10.19 Form of Amendment to Restricted Stock Agreements, dated * as of July 15, 1998, between TECO Energy, Inc. and certain senior executives under the TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit 10.2, Form 10-Q for the quarter ended Sept. 30, 1998 of Tampa Electric Company). 10.20 Form of Restricted Stock Agreement between TECO Energy, * Inc. and G. F. Anderson under the TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 1998 of Tampa Electric Company). 10.21 TECO Energy, Inc. 1997 Director Equity Plan * (Exhibit 10, Form 10-Q for the quarter ended June 30, 1997 of Tampa Electric Company). 10.22 Form of Nonstatutory Stock Option under the TECO * Energy, Inc. 1997 Director Equity Plan (Exhibit 10, Form 10-Q for the quarter ended June 30, 1997 of Tampa Electric Company).
12. Ratio of earnings to fixed charges. 68 23. Consent of Independent Accountants. 69 24.1 Power of Attorney. 70 24.2 Certified copy of resolution authorizing Power 72 of Attorney. 27.1 Financial Data Schedule (EDGAR filing only).
* 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.