Item 1. BUSINESS.
TECO ENERGY
TECO Energy, Inc. (TECO Energy) was incorporated in Florida in 1981, as part of a restructuring in which it became the parent corporation of Tampa Electric Company.
TECO Energy currently owns no operating assets but holds all of the common stock of Tampa Electric Company and directly, or through its subsidiary TECO Diversified, Inc., the other subsidiaries listed below. TECO Energy is a public utility holding company exempt from registration under the Public Utility Holding Company Act of 1935.
TECO Energy's significant business segments are identified below:
-- Tampa Electric Company, a Florida corporation and TECO Energy's largest subsidiary, through its Tampa Electric division (Tampa Electric) provides retail electric service to more than 575,000 customers in West Central Florida with a net system generating capability of 3,899 megawatts (MW). Peoples Gas System, a division of Tampa Electric Company (PGS), is engaged in the purchase, distribution and marketing of natural gas for residential, commercial, industrial and electric power generation customers in Florida. PGS was merged into Tampa Electric Company as part of the 1997 TECO Energy acquisition of Lykes Energy, Inc. With more than 272,000 customers, PGS 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 2001 was 1.1 billion therms.
-- TECO Transport Corporation (TECO Transport), a Florida corporation, owns no operating assets but owns all of the common stock of four subsidiaries which transport, store and transfer coal and other dry-bulk commodities.
-- TECO Coal Corporation (TECO Coal), a Kentucky corporation, owns no operating assets but owns all of the common stock of eight subsidiaries that own mineral rights, and own or operate surface and underground mines, synthetic fuel facilities, and coal processing and loading facilities in Kentucky, Tennessee and Virginia.
-- TECO Power Services Corporation (TECO Power Services), a Florida corporation, has subsidiaries that have interests in independent power projects in Florida, Virginia, Hawaii, Arkansas, Mississippi, Texas, Arizona and Guatemala, and has investments in unconsolidated affiliates that participate in independent power projects and electric distribution in other parts of the U.S. and the world.
TECO Energy's other diversified businesses include the following corporations identified below:
-- TECO Coalbed Methane, Inc. (TECO Coalbed Methane), an Alabama corporation, participates in the production of natural gas from coalbeds located in Alabama's Black Warrior Basin.
-- TECO Solutions, Inc. (TECO Solutions), a Florida corporation, has subsidiaries that provide engineering and energy services to customers primarily in Florida and in California, mechanical contracting, air conditioning, electrical and plumbing systems and repair and maintenance services in Florida and gas management and marketing services to large municipal, industrial and power generation customers throughout the southeast.
For financial information regarding TECO Energy's significant business segments, see Notes to the Consolidated Financial Statements -- Note K, Segment Information.
TECO Energy and its subsidiaries had 6,315 employees as of Dec. 31, 2001.
TAMPA ELECTRIC--Electric Operations
Tampa Electric Company was incorporated in Florida in 1899 and was reincorporated in 1949. 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. The retail territory served 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.
Tampa Electric had 2,823 employees as of Dec. 31, 2001, of which 984 were represented by the International
Brotherhood of Electrical Workers (IBEW) and 298 by the Office and Professional Employees International Union (OPEIU).
In 2001, approximately 47 percent of Tampa Electric's total operating revenue was derived from residential sales, 29 percent from commercial sales, 9 percent from industrial sales and 15 percent from other sales, including bulk power sales for resale.
The sources of operating revenue and megawatt-hour sales for the years indicated were as follows:
No significant part of Tampa Electric's business is dependent upon a single customer or a few customers, the loss of any one or more of whom would have a significant adverse effect on Tampa Electric. IMC-Agrico, a large phosphate producer, is Tampa Electric's largest customer representing less than 3 percent of Tampa Electric's 2001 base revenues.
Tampa Electric's business is not highly seasonal, but winter peak loads are experienced due to electric heating fewer daylight hours and colder temperatures, and summer peak loads are experienced due to use of air conditioning and other cooling equipment.
Regulation
The retail operations of Tampa Electric are regulated by the Florida Public Service Commission (FPSC), which has jurisdiction over retail rates, quality of service and reliability, 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, plus a reasonable return on invested capital.
The costs of owning, operating and maintaining the utility system, other than fuel, purchased power, conservation and certain environmental costs, are recovered through base rates. These costs include operation and maintenance expenses, depreciation and taxes, as well as a return on Tampa Electric's investment in assets used and useful in providing electric service (rate base). The rate of return on rate base, which is intended to approximate Tampa Electric's weighted cost of capital, primarily includes its costs for debt, deferred income taxes at a zero cost rate and an allowed return on common equity. Base rates are determined in FPSC rate 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 in the Utility Regulation -- Rate Stabilization Strategy section.
Fuel, purchased power, conservation and certain environmental costs are recovered through levelized monthly charges established pursuant to the FPSC's cost recovery clauses. These charges, which are reset annually in an FPSC proceeding, are based on estimated costs of fuel, environmental compliance, conservation programs and purchased power and estimated customer usage for a specific recovery period, with a true-up adjustment to reflect the variance of actual costs from the projected charges. The FPSC may disallow recovery of any costs that it considers imprudently incurred.
Tampa Electric is also subject to regulation by the Federal Energy Regulatory Commission (FERC) in various respects including wholesale power sales, certain wholesale power purchases, transmission services, and accounting and depreciation
practices. See Utility Regulation -- Regional Transmission Organization section.
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 page 6.
TECO Transport sells transportation services, and TECO Power Services sells generating capacity and energy to Tampa Electric in addition to other 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 be disallowed for recovery from Tampa Electric's customers. (See Utility Regulation section.) Except for transportation services performed by TECO Transport under the U.S. bulk cargo preference program, the prices charged by TECO Transport to third-party customers are not subject to regulatory oversight. See also the TECO Power Services section.
Competition
Tampa Electric's retail electric business is substantially free from direct competition with other electric utilities, municipalities and public agencies. At the present time, the principal form of competition at the retail level consists of natural gas and propane for residential and commercial customers and self-generation which is available to larger users of electric energy. Such users may seek to expand their options through various initiatives including legislative and/or regulatory changes that would permit competition at the retail level. Tampa Electric intends to take all appropriate actions to retain and expand its retail business, including managing costs and providing high- quality service to retail customers.
In 1999, the Federal Energy Regulatory Commission (FERC) approved a market- based sales tariff for Tampa Electric which allows Tampa Electric to sell excess power at market prices within Florida. The FERC had already approved market- based prices for interstate sales for Tampa Electric and the other investor- owned utilities (IOUs) operating in the state; however, Tampa Electric is the only IOU with intrastate market-based sales authority.
There is presently active competition in the wholesale power markets in Florida, and this is increasing largely as a result of the Energy Policy Act of 1992 and related federal initiatives. For independent power producers, this Act removed certain regulatory barriers and required utilities to transmit power from such producers, utilities and others to wholesale customers as more fully described below.
In April 1996, the FERC issued its Final Rule on Open Access Non- discriminatory Transmission, Standard Costs, Open Access Same-time Information System (OASIS) and Standards of Conduct. This rule works to open access for wholesale power flows on transmission systems. Utilities such as Tampa Electric owning transmission facilities are required to provide services to wholesale transmission customers comparable to those they provide to themselves on comparable terms and conditions, including price. Among other things, the rules require transmission services to be unbundled from power sales and owners of transmission systems to take transmission service under their own transmission tariffs.
FERC requires transmission system owners 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. FERC's authority over this requirement was recently upheld by the Supreme Court. Tampa Electric, together with other utilities, has implemented an OASIS system and believes it is in compliance with the Standards of Conduct.
In December 1999, the FERC issued Order No. 2000, dealing with Regional Transmission Organizations (RTOs). This rule is driven by the FERC's continuing effort to effect open access to transmission facilities in large, regional markets. In FERC filings in October 2000 and December 2000, Tampa Electric agreed with the other IOUs operating in Florida to form an RTO to be known as GridFlorida LLC. As proposed, the RTO would independently control the transmission assets of the filing utilities, as well as other utilities in peninsular Florida that choose to join. The FERC tentatively approved GridFlorida in March 2001, but has not finally ruled on a May 2001 compliance filing of the applicants.
In May 2001, the FPSC questioned the prudence of the three filing utilities joining GridFlorida as conditionally approved by FERC. The three utilities requested and the FPSC granted the opening of an accelerated docket regarding the prudence of GridFlorida. In December 2001, the FPSC ruled that, while the three IOUs were prudent in their actions to set up GridFlorida, the FPSC was not satisfied with the transmission owning features of GridFlorida nor with the proposal that any of the filing utilities transfer ownership of their assets to GridFlorida. Accordingly, the FPSC ordered the three IOUs to file a revised version of GridFlorida which was filed with the FPSC in late March 2002. Tampa Electric plans to take an active role in monitoring and influencing the development of other possible RTOs in the southeast region.
Florida Governor Jeb Bush established the 2020 Energy Study Commission in 2000 to address several issues by December 2001, including current and future reliability of electric and natural gas supply, emerging energy supply and delivery options, electric industry competition, environmental impacts of energy supply, energy conservation and fiscal impacts of energy supply options on taxpayers and energy providers. The Study Commission completed its efforts and published its final report in December 2001. The Study Commission's final recommendations include, among other things, elimination of barriers to entry for
merchant power generators, an open competitive wholesale electric market, transfer of regulated generating assets to unregulated affiliates or sale to others, Florida electric system reliability and consumer protection. A proposal is expected to be forwarded to the legislature by the Governor for possible action as early as the 2002 legislative session. It is unclear at this time if this proposed legislation would pass.
Fuel
Approximately 96 percent of Tampa Electric's generation for 2001 was coal- fired, with oil and natural gas each representing 2 percent. Tampa Electric used its generating units to meet approximately 84 percent of the system load requirements with the remaining 16 percent coming from purchased power. A slightly lower level of coal generation as a percentage of total generation is anticipated for 2002.
Tampa Electric's average delivered fuel cost per million BTU and average delivered cost per ton of coal burned have been as follows:
Tampa Electric's generating stations burn fuels as follows: Gannon Station burns low-sulfur coal; Big Bend Station, which has sulfur dioxide scrubber capabilities, burns a combination of low-sulfur coal, petroleum coke and coal of a somewhat higher sulfur content; Polk Power Station burns high-sulfur coal, which is gasified and subjected to sulfur removal prior to combustion, natural gas and oil; Hookers Point Station burns low-sulfur oil; and Phillips Station burns oil of a somewhat higher sulfur content.
Coal. Tampa Electric used approximately 7.3 million tons of coal during 2001 and estimates that its coal consumption will be about 7.1 million tons for 2002. During 2001, Tampa Electric purchased approximately 44 percent of its coal under long-term contracts with five suppliers, and 56 percent of its coal in the spot market. During 2000, Tampa Electric purchased approximately 61 percent of its coal under long-term contracts with five suppliers, and 39 percent of its coal in the spot market or under intermediate-term purchase agreements. Tampa Electric expects to obtain approximately 60 percent of its coal requirements in 2002 under long-term contracts with five suppliers and the remaining 40 percent in the spot market. Tampa Electric's remaining long-term coal contracts provide for revisions in the base price to reflect changes in a wide range of cost factors and for suspension or reduction of deliveries if environmental regulations should prevent Tampa Electric from burning the coal supplied, provided that a good-faith effort has been made to continue burning such coal. For information concerning transportation services and sales of coal by affiliated companies to Tampa Electric, see TECO Transport on pages 10 and 11 and TECO Coal on page 11.
In 2001, about 63 percent of Tampa Electric's coal supply was deep-mined, approximately 33 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 of any future mining laws and regulations.
Oil. Tampa Electric had supply agreements through Dec. 31, 2002 for No. 2 fuel oil and No. 6 fuel oil for its Polk and Phillips stations, and its combustion turbine units at prices based on Gulf Coast Cargo spot prices.
Natural Gas. As of December 2001, Tampa Electric had no committed gas contracts for the Polk 2 Unit as purchases were made on the spot market.
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 give Tampa Electric rights to the use of rights of way and other public property to place its facilities, and are irrevocable and 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. 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; otherwise, based on judicial precedent, Tampa Electric is able to keep its facilities in place subject to reasonable rules and regulations imposed by the municipalities.
Tampa Electric has franchise agreements with 13 incorporated municipalities within its retail service area. These agreements have various expiration dates ranging from December 2005 to September 2021.
Franchise fees payable by Tampa Electric, which totaled $24.3 million in 2001, 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 state or county rights-of-way granted by the Florida Department of Transportation or 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 Polk and Pasco counties expire in 2004 and 2033, respectively.
Environmental Matters
Tampa Electric Company is a party to a consent decree with the Environmental Protection Agency (EPA) and the U.S. Department of Justice, effective Oct. 5, 2000, and a consent final judgement with the Florida Department of Environmental Protection (FDEP) effective December 7, 1999. Pursuant to these consent decrees, allegations of violations of New Source Review requirements of the Clear Air Act were resolved, provision was made for environmental controls and pollution reductions, and Tampa Electric is committed to a comprehensive program that will dramatically decrease emissions from the company's power plants.
The emission reduction plan included specific detail with respect to the availability of the scrubbers and earlier incremental NOx reduction efforts on Big Bend Units 1, 2 and 3 and the repowering of the company's coal-fired Gannon Station to natural gas. Engineering for the repowering project began in January 2000, and Tampa Electric anticipates that commercial operation for the first repowered unit is expected by May 1, 2003. The repowering of the second unit is scheduled for completion by May 1, 2004. When these units are repowered, the station will be renamed the Bayside Power Station and will have total station capacity of about 1,800 megawatts (nominal) of natural gas-fueled electric generation.
In November 2000, the FPSC approved recovery through the Environmental Cost Recovery Clause of costs incurred to improve the availability and removal efficiency for Tampa Electric's Big Bend 1, 2 and 3 scrubbers, to reduce particulate matter emissions, and to reduce NOx emissions. The approved cost recovery for these various environmental projects through customers' bills started in January 2001.
Tampa Electric Company is one of several potentially responsible parties for certain superfund sites and, through its Peoples Gas System division, for certain superfund and 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 $22 million over the next 10 years. The environmental remediation costs associated with these sites have been recorded on the accompanying consolidated balance sheet and are not expected to have a significant impact on customer prices.
Expenditures. During the five years ended Dec. 31, 2001, Tampa Electric spent $141.0 million on capital additions to meet environmental requirements. Tampa Electric spent an estimated $11.6 million in 2001 on environmental projects.
Environmental expenditures are estimated at $11.5 million for 2002, and $21.7 million during the years 2003 through 2006. Approximately half of the $21.7 million is for the development of technologies for further reduction of NOx emissions at Big Bend Station beginning in 2006. The balance of the estimated expenditures are for continued improvement of electrostatic precipitators for particulate matter emissions reductions, and continued improvements of the scrubber systems for SO2 reductions as required by the EPA consent decree.
To date Tampa Electric has spent approximately $26.1 million for compliance with the EPA consent decree at Big Bend Station for reduction of NOx and particulate matter emissions and to improve the scrubber systems to reduce SO2 emissions. Tampa Electric has also spent $260.2 million excluding allowance for funds used during construction (AFUDC), on projects leading to the repowering of the company's coal-fired Gannon Station to fire natural gas, to meet the EPA consent decree condition of eliminating coal firing at Gannon Station.
PEOPLES GAS SYSTEM--Gas Operations
Peoples Gas System (PGS) operates as the Peoples Gas System division of Tampa Electric Company. PGS is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in the State of Florida.
PGS uses two interstate pipelines to receive gas for sale or other delivery to customers connected to its distribution system. PGS does not engage in the exploration for or production of natural gas. Currently, PGS operates a natural gas distribution system that serves over 272,000 customers. The system includes approximately 9,000 miles of mains and over 4,400 miles of service lines.
In 2001, the total throughput for PGS was 1.1 billion therms. Of this total throughput, 17 percent was gas purchased and resold to retail customers by PGS, 74 percent was third party supplied gas delivered for retail customers, and 9 percent was gas sold off-system. Industrial and power generation customers consumed approximately 67 percent of PGS' annual therm volume. Commercial customers used approximately 28 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 25 percent of total revenues. New residential construction including natural gas and conversions of existing residences to gas have steadily increased since the late 1980's.
Natural gas has historically been used in many traditional industrial and commercial operations throughout Florida, including production of products such as steel, glass, ceramic tile and food products. Gas climate control technology is expanding throughout Florida, and commercial/industrial customers, including schools, hospitals, office complexes and churches, are utilizing this technology.
Within the PGS operating territory, large cogeneration facilities utilize gas-fired technology in the production of electric power and steam. Over the past three years, the company has transported, on average, about 296 million therms annually to facilities involved in cogeneration.
Revenues and therms for PGS for the years ended Dec. 31, are as follows:
Revenues Therms (millions) 2001 2000 1999 2001 2000 1999 ------ ------ ------ ------- ------- ------- Residential $ 88.2 $ 73.2 $ 59.0 58.8 57.6 52.1 Commercial 163.6 145.8 125.5 308.9 292.1 273.5 Industrial 50.4 51.7 29.3 346.5 374.1 331.9 Power Generation 11.6 10.7 10.4 403.5 418.6 405.2 Other revenues 39.1 33.0 27.5 - - - ------ ------ ------ ------- ------- ------- Total $352.9 $314.4 $251.7 1,117.7 1,142.4 1,062.7 ====== ====== ====== ======= ======= =======
PGS had 639 employees as of Dec. 31, 2001. A total of 89 employees in six of the company's 15 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 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, plus a reasonable return on invested capital.
The basic costs of providing natural gas service, other than the costs of purchased gas and interstate pipeline capacity, are recovered through base rates. Base rates are designed to recover the costs of owning, operating and maintaining the utility system. The rate of return on rate base, which is intended to approximate PGS' weighted cost of capital, primarily includes its cost for debt, deferred income taxes at a zero cost rate, and an allowed return on common equity. Base rates are determined in FPSC proceedings which occur at irregular intervals at the initiative of PGS, the FPSC or other parties.
PGS recovers the costs it pays for gas supply and interstate transportation for system supply through the Purchased Gas Adjustment (PGA) clause. This charge is designed to recover the costs incurred by PGS for purchased gas, and for holding and using interstate pipeline capacity for the transportation of gas it sells to its customers. These charges are adjusted monthly based on a cap approved annually in an FPSC hearing. The cap is based on estimated costs of purchased gas and pipeline capacity, and estimated customer usage for a specific recovery period, with a true-up adjustment to reflect the variance of actual costs and usage from the projected charges for prior periods. For a description of the most recent adjustment, see the Utility Regulation - Cost Recovery Clauses section.
In addition to its base rates and purchased gas adjustment clause charges for system supply customers, PGS customers (except interruptible customers) also pay a per-therm charge for all gas consumed to recover the costs incurred by PGS 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 February 2000, the FPSC approved a rule that would require natural gas utilities to offer transportation-only service to all non-residential customers. See the Utility Regulation - Utility Competition-Gas section.
PGS had over 8,000 transportation customers as of Dec. 31, 2001. PGS continues to receive its base rate for distribution regardless of whether a customer decided to opt for transportation-only service, or continue bundled service. It is, therefore, not expected that unbundling will have an adverse effect on PGS' earnings in the future.
In addition to economic regulation, PGS is subject to the FPSC's safety jurisdiction, pursuant to which the FPSC regulates the construction, operation and maintenance of PGS' distribution system. In general, the FPSC has implemented this by adopting the Minimum Federal Safety Standards and reporting requirements for pipeline facilities and transportation of gas prescribed by the U.S. Department of Transportation in Parts 191, 192 and 199, Title 49, Code of Federal Regulations.
PGS is also subject to federal, state and local environmental laws and regulations pertaining to air and water quality, land use, noise and aesthetics, solid waste and other environmental matters.
Competition
PGS is not in direct competition with any other regulated distributors of natural gas for customers within its service areas. At the present time, the principal form of competition for residential and small commercial customers is from companies providing other sources of energy and energy services including fuel oil, electricity and in some cases propane. PGS has taken actions to retain and expand its commodity and transportation business, including managing costs and providing high quality service to customers. The NaturalChoice Transportation Service (NCTS) program that began in November 2000 is expected to improve the competitiveness of natural gas for commercial load.
Competition is most prevalent in the large commercial and industrial markets. In recent years, these classes of customers have been targeted by competing companies seeking to sell alternate fuels or transport gas through other facilities, thereby bypassing PGS facilities. Many of these competitors are larger natural gas marketers with a national presence. The FPSC has allowed PGS to adjust rates to meet competition for customers who use more than 100,000 therms annually.
Gas Supplies
PGS purchases gas from various suppliers depending on the needs of its customers. The gas is delivered to the PGS distribution system through two interstate pipelines on which PGS has reserved firm transportation capacity for delivery by PGS to its customers.
Gas is delivered by Florida Gas Transmission Company (FGT) through more than 54 interconnections (gate stations) serving PGS' operating divisions. In addition, PGS' Jacksonville Division receives gas delivered by the South Georgia Natural Gas Company (South Georgia) pipeline through a gate station located northwest of Jacksonville.
Companies with firm pipeline capacity receive priority in scheduling deliveries during times when the pipeline is operating at its maximum capacity. PGS presently holds sufficient firm capacity to permit it to meet the gas requirements of its system commodity customers, except during localized emergencies affecting the PGS distribution system and on abnormally cold days.
Firm transportation rights on an interstate pipeline represent a right to use the amount of the capacity reserved for transportation of gas on any given day. PGS pays reservation charges on the full amount of the reserved capacity whether or not it actually uses such capacity on any given day. When the capacity is actually used, PGS pays a volumetrically-based usage charge for the amount of the capacity actually used. The levels of the reservation and usage charges are regulated by FERC. PGS actively markets any excess capacity available on a day-to-day basis to partially offset costs recovered through the Purchased Gas Adjustment Clause.
PGS procures natural gas supplies using base load and swing supply contracts with various suppliers along with spot market purchases. Pricing generally takes the form of either a variable price based on published indices, or a fixed price for the contract term.
Neither PGS nor any of the interconnected interstate pipelines have 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, or at a published index price, and in either case pays the customer for charges incurred for interstate pipeline transportation to the PGS system.
Franchises
PGS holds franchise and other rights with approximately 90 municipalities throughout Florida. These include the cities of Jacksonville, Daytona Beach, Eustis, Fort Myers, Brooksville, Orlando, Tampa, St. Petersburg, Sarasota, Avon Park, Frostproof, Palm Beach Gardens, Pompano Beach, Fort Lauderdale, Hollywood, North Miami, Miami Beach, Miami, and Panama City. These franchises give PGS a right to occupy municipal rights-of-way within the franchise area. 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. Several franchises contain purchase options with respect to the purchase of PGS' property located in the franchise area, if the franchise is not renewed; otherwise, based on judicial precedent, PGS is able to keep its facilities in place subject to reasonable rules and regulations imposed by the municipalities.
PGS' franchise agreements with the incorporated municipalities within its service area have various expiration dates ranging from September 2002 through April 2031.
In March 2000, the franchise agreement between the city of Lakeland (City) and PGS expired. The City has initiated legal proceedings seeking a declaration of the City's rights to acquire the PGS facilities under the franchise. PGS has filed defenses and counter claims and several hearings have been held. While PGS believes it is best suited to serve the customers in the City, it cannot at this time predict the ultimate outcome of these proceedings. PGS is continuing to serve under substantially
the same terms as contained in the franchise in the absence of other rules and regulations being adopted by the City. The Lakeland franchise contributed about $4.5 million of total revenue to PGS' results in 2001.
Franchise fees payable by PGS, which totaled $8.9 million in 2001, are calculated using various formulas which are based principally on natural gas revenues. Franchise fees are collected from only those customers within each franchise area.
Utility operations in areas outside of incorporated municipalities are conducted in each case under one or more permits to use state or county rights- of-way granted by the Florida Department of Transportation or the county commissioners of such counties. There is no law limiting the time for which such permits may be granted by counties. There are no fixed expiration dates and these rights are, therefore, considered perpetual.
Environmental Matters
PGS's operations are subject to federal, state and local statutes, rules and regulations relating to the discharge of materials into the environment and the protection of the environment generally that require monitoring, permitting and ongoing expenditures.
Tampa Electric Company is one of several potentially responsible parties for certain superfund sites and, through its Peoples Gas System division, for certain superfund and former manufactured gas plant sites. See the previous discussion in the Environmental Matters section of Tampa Electric - Electric Division on page 6.
Expenditures. During the five years ended Dec. 31, 2001, PGS has not incurred any material capital additions to meet environmental requirements, nor are any anticipated for 2002 through 2006.
TECO POWER SERVICES
TECO Power Services (TPS) through its subsidiaries, has interests in independent power projects in Florida, Virginia, Hawaii, Mississippi, Arkansas, Texas, Arizona and Guatemala, and has investments in unconsolidated affiliated entities that participate in independent power projects in other parts of the U.S. and the world. It had 309 employees as of Dec. 31, 2001.
Like Tampa Electric, the U.S. operations of TPS are subject to federal, state and local environmental laws and regulations covering air quality, water quality, land use, power plant, substation and transmission line siting, noise and aesthetics, solid waste and other environmental matters.
Hardee Power Partners (Hardee Power), a Florida limited partnership whose general and limited partners are wholly owned subsidiaries of TPS, owns the Hardee Power Station, a 295-megawatt combined cycle electric generating facility located in Hardee County, Florida, which began commercial operation in 1993. In 1993, Hardee Power entered into 20-year power supply agreements for all the capacity and energy of the Hardee Power Station, with Seminole Electric Cooperative (Seminole Electric), a Florida electric cooperative that provides wholesale power to 10 electric distribution cooperatives, and with Tampa Electric. Under the Seminole Electric agreement, Hardee Power has agreed to supply Seminole Electric with an additional 145 megawatts of capacity during the first 10 years of the contract, which it is purchasing from Tampa Electric's coal-fired Big Bend Unit Four for resale to Seminole Electric. A 75-megawatt simple-cycle combustion turbine expansion at the Hardee Power Station was completed in May 2000. The added capacity from this expansion serves Tampa Electric through 2012.
In 2000, TPS increased its ownership to 100 percent of Central Generadora Electrica San Jose, Ltda. (CGSE), the owner of a project located in Guatemala, which consists of a single-unit pulverized-coal baseload facility (the San Jose Power Station), including port modifications to accommodate the importation of coal. This facility is the first coal-fueled plant in Central America and meets environmental standards set by the World Bank. The San Jose Power Station has a U.S. dollar-denominated power sales agreement with Empresa Electrica de Guatemala, S.A. (EEGSA), to provide 120 megawatts of capacity for 15 years beginning in 2000. Political risk insurance has been obtained for currency inconvertibility, expropriation and political violence covering up to 100 percent of TPS' equity investment and economic returns.
Tampa Centro Americana de Electricidad, Limitada (TCAE), an entity 96- percent owned by TPS Guatemala One, Inc. (TPS Guatemala One), a subsidiary of TPS, has a U.S. dollar-denominated power sales agreement to provide 78 megawatts of capacity from the Alborada Power Station to EEGSA for a 15-year period ending in 2010. EEGSA is responsible for providing the fuel for the plant, with TPS providing assistance in fuel administration. TPS has obtained $29 million of limited recourse financing for the Alborada Power Station and political risk insurance for currency inconvertibility, expropriation and political violence covering up to 100 percent of TPS' equity investment and economic returns from The Overseas Private Investment Corporation (OPIC).
EEGSA is private distribution and generation company formed in 1994 serving more than 630,000 customers. EEGSA's service territory includes the capital of Guatemala, Guatemala City. In 1998, a consortium that includes TPS, Iberdrola, an electric utility in Spain, and Electricidade de Portugal, an electric utility in Portugal, completed the purchase of an 80-percent ownership interest in EEGSA for $520 million. TPS owns a 30-percent interest in this consortium and contributed $100 million in equity. The consortium obtained limited-recourse debt financing for a portion of the purchase price.
TM Power Ventures LLC (TMPV) was created by TPS and Mosbacher Power Partners, Ltd. (Mosbacher Power), an independent power company headquartered in Houston, to jointly develop, own and operate domestic and international independent power projects. Under this arrangement, TPS provides capital and technical expertise to Mosbacher Power. In 1998, TPS, through TMPV, made certain loans to two existing projects and acquired approximately a 13-percent interest in a repowered
independent power project in the Czech Republic. TMPV, NRG Energy, El Paso Energy International and Stredoceske Energeticke Zavody (STE), a Czech regional distribution company, are owners of the project. The facility completed its expansion to a total of 344 megawatts in the first quarter of 2000.
TPS, through TMPV, has a 95-percent interest in the Commonwealth Chesapeake Power Station, a 312-megawatt power plant on the Delmarva Peninsula of Virginia. The first phase of 134 megawatts went into service in the third quarter of 2000, and the second phase went into service in August 2001.
TPS is a 50-percent owner in the Hamakua Energy Project, a 60-megawatt combined cycle cogeneration facility in Hamakua, Hawaii. The facility was constructed and placed into service during 2000. TPS and J.A. Jones Ventures jointly own and operate the project under a 30-year power purchase agreement with Hawaii Electric Light Company.
In the first quarter of 2001, TPS sold its minority interest in Energia Global International, Ltd. (EGI), a Bermuda based energy development firm. As part of the sale TPS took an after tax charge of $6.1 million ($9.3 million pre- tax), to adjust the asset valuation of this investment.
In September 2000, TPS provided a $93-million investment in the form of a loan related to Panda Energy International's (Panda) Texas Independent Energy Projects (TIE). This investment, under certain circumstances, gives TPS an opportunity for an effective economic interest, estimated at 75-percent, in Panda's 1,000-megawatt interest in these projects. The projects operate as gas- fired, combined-cycle units in the Texas (ERCOT) market. The projects were brought online in phases beginning in December 2000, with all the capacity in service in the third quarter of 2001.
In October 2000, TPS acquired from GenPower LLC full ownership of two independent power projects being developed in Arkansas and Mississippi. The combined capacity of the two projects are planned to be nearly 1,200 megawatts. TPS' equity investment in the projects is expected to be approximately $412 million. The two 599-megawatt facilities, known as the McAdams and Dell projects, will be natural gas-fired combined-cycle plants. Both projects will be interconnected with the Entergy transmission system and will be able to sell electricity to wholesale customers in the Southeast and Midwest, including the states of Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee and Kentucky. Financing for these plants is expected to be completed in 2002. Dell and McAdams are expected to begin commercial operations in May 2003.
In November 2000, TPS announced a joint venture with Panda to build, own and operate two natural gas power plants located in El Dorado, Arkansas and Gila Bend, Arizona. After taking into account the preferred return, TPS' economic interest in the project is estimated at 75 percent. The 2,200-megawatt Union plant in El Dorado, Arkansas is under construction. The first phase is expected to begin commercial operation in the second half of 2002, with commercial operation of the entire facility slated for the following year. It is expected to sell power primarily to utilities and industrial customers in Arkansas, Louisiana, eastern Texas and Mississippi. The other project in Gila Bend, Arizona, is also under construction. The first phase is expected to begin commercial operation in the first quarter of 2003 with commercial operation of the entire facility in the third quarter of 2003. Electricity from this 2,145- megawatt plant, which is located southwest of Phoenix, is planned to be sold in Arizona, southern California, Nevada and New Mexico. In February 2002, TPS entered into an agreement requiring TPS to purchase 100 percent of the Panda Partners interest in the joint venture in 2007 unless Panda chooses to remain a partner by cancelling the agreement and paying a cancellation fee.
In June 2001, TPS and Panda closed on a bank financing for the Union and Gila River power stations. This $2.175 billion bank financing included $1.675 billion in five-year non-recourse debt and $500 million in equity bridge loans guaranteed by TECO Energy. Equity contributions from the joint venture, which TECO Energy has guaranteed, will be required to fund additional construction costs of up to approximately $657 million. The equity bridge financing must be repaid in four equal installments coincident with Phase 2 and Phase 4 completion of each facility, and the equity contributions must be made over the period that ends with commercial operation of Phase 4 of the projects. The TPS equity investment in these projects at commercial operation is expected to be approximately $1.2 billion.
In March 2001, TPS acquired American Electric Power's (AEP) Frontera Power Station, located near McAllen, Texas. Frontera is a 477-megawatt natural gas- fired combined-cycle plant. Frontera is capable of selling power domestically, as well as into the Mexican power market, through a direct interconnection with Comision de Federal Electricidad, the Mexican power authority. TPS expects to finance the acquisition in 2002.
The Enron bankruptcy creates uncertainty for four TPS generation projects because an Enron subsidiary, NEPCO, is the engineering, procurement and construction (EPC) contractor for the four projects. NEPCO has continued construction and engineering work on these power plants and currently construction of all four plants is on schedule. See the discussion in the Enron Exposure section.
For financial information about geographic areas, see Note K to the Consolidated Financial Statements.
See the discussion of the risks applicable to TPS in the Investment Considerations section.
TECO TRANSPORT
TECO Transport owns all of the common stock of four subsidiaries which transport, store and transfer coal and other dry-bulk commodities. These subsidiaries include TECO Ocean Shipping, Inc. (Ocean Shipping, previously Gulfcoast Transit Company), TECO Barge Line, Inc. (TECO Barge, previously Mid- South Towing Company), TECO Bulk Terminal, LLC (Bulk
Terminal, previously Electro-Coal Transfer, LLC) and TECO Towing Company. TECO Transport currently owns no operating assets.
TECO Transport and its subsidiaries had 1,066 employees as of Dec. 31, 2001.
TECO Transport's subsidiaries perform substantial services for Tampa Electric. In 2001, approximately 55 percent of TECO Transport's revenues were from third-party customers and 45 percent were from Tampa Electric. The pricing for services performed by TECO Transport's operating companies for Tampa Electric is based on a fixed-price per ton, generally adjusted quarterly for changes in certain fuel and price indices. Most of the third-party utilization of the ocean-going barges is for domestic and international movements of other dry-bulk commodities and domestic phosphate movements. Both the terminal and river transport operations handle a variety of dry-bulk commodities for third party customers.
A substantial portion of TECO Transport's business is dependent upon Tampa Electric, phosphate customers, steel industry customers, grain customers, coal and petroleum coke customers, and participation in the U.S. Department of Agriculture's cargo preference program.
Ocean Shipping transports products in the Gulf of Mexico and worldwide, and TECO Barge operates on the Mississippi, Ohio and Illinois rivers and their tributaries. Their primary competitors are other barge and shipping lines and railroads as well as a number of other companies offering transportation services on the waterways used by TECO Transport's subsidiaries. Ocean Shipping is the largest US flag coastwise bulk operator based on capacity, while Teco Barge is in the top ten based on number of barges of companies in its business. To date, physical and technological improvements have allowed ship and barge operators to maintain competitive rate structures with alternate methods of transporting bulk commodities when the origin and destination of such shipments are contiguous to navigable waterways.
Bulk Terminal operates the largest major transfer and storage terminal on the Mississippi River south of New Orleans. Demand for the use of such terminals is dependent upon customers' use of water transportation versus alternate means of moving bulk commodities and the demand for these commodities. Competition consists primarily of mid-stream operators and three other land-based terminals.
Competition within TECO Transports markets is based primarily on geographic markets served, pricing, and service level. The majority of the ocean and all of the river business is subject to the Jones Act which prohibits the use of non-US flag vessels for movement between US ports.
The business of TECO Transport's subsidiaries, taken as a whole, is not subject to significant seasonal fluctuation, but is sensitive to economic conditions.
The Interstate Commerce Act exempts from regulation water transportation of certain dry-bulk commodities. In 2001, all transportation services provided by TECO Transport's subsidiaries were within this exemption.
TECO Transport's subsidiaries are subject to the provisions of the Clean Water Act of 1977 which authorizes the Coast Guard and the EPA to assess penalties for oil and hazardous substance discharges. Under this Act, these agencies are also empowered to assess clean-up costs for such discharges. In 2001, TECO Transport spent $.1 million for environmental compliance. Environmental expenditures are estimated at $.3 million in 2002, primarily for work on solid waste disposal and storm water drainage at the Bulk Terminal facility in Louisiana and for expenses related to oil and bilge water disposal at its river-barge repair facility in Illinois.
TECO COAL
TECO Coal owns no operating assets but holds all of the common stock of Gatliff Coal Company (Gatliff), Rich Mountain Coal Company (Rich Mountain), Clintwood Elkhorn Mining Company (Clintwood), Pike-Letcher Land Company (Pike- Letcher,) Premier Elkhorn Coal Company (Premier), Bear Branch Coal Company (Bear Branch) and Perry County Coal Corporation (Perry County). Rich Mountain has no reserves; it mines coal reserves owned by Gatliff. TECO Coal's subsidiaries own mineral rights, and own or operate surface and underground mines, synthetic fuel facilities and coal processing and loading facilities in Kentucky, Virginia and Tennessee.
TECO Coal and its subsidiaries had 594 employees as of Dec. 31, 2001.
In 2001, TECO Coal subsidiaries sold 10.1 million tons of coal, with approximately 99 percent, or 9.9 million tons, sold to third parties other than Tampa Electric. TECO Coal's long-term contract with Tampa Electric ended in December 1999. Of the total sold, 3.2 million tons were produced and sold as synthetic fuel.
In November 2000, TECO Coal acquired Perry County Coal Corporation (Perry County), which owns or controls in excess of 23 million tons of low sulfur reserves and operates both deep and surface contract mines along with a preparation plant and two loadouts. Perry County produced and sold 2.3 million tons of coal in 2001.
In January 2000, TECO Coal purchased synthetic fuel (synfuel) facilities which were relocated to the Premier Elkhorn and Clintwood Elkhorn mines. The 3.2 million tons of synfuel produced in 2001 replaced some of TECO Coal's conventional coal production in 2001. Synthetic fuel production for 2002 is expected to increase modestly from 2001 levels. Sales of the fuel processed through these types of facilities are eligible for non-conventional fuels tax credits under Section 29 of the Internal Revenue Code, which are available through 2007. TECO Coal received a Private Letter Ruling from the Internal Revenue Service confirming that the facilities produce a qualified fuel eligible for Section 29 tax credits available for the production of such non-conventional fuels.
Primary competitors of TECO Coal's subsidiaries are other coal suppliers, many of which are located in Central Appalachia. To date, TECO Coal has been able to compete for coal sales by mining high-quality steam and specialty coals and by effectively managing production and processing costs.
The operations of underground mines, including all related surface facilities, are subject to the Federal Coal Mine Safety and Health Act of 1977. TECO Coal's subsidiaries are also subject to various Kentucky, Tennessee and Virginia
mining laws which require approval of roof control, ventilation, dust control and other facets of the coal mining business. Federal and state inspectors inspect the mines to ensure compliance with these laws. TECO Coal believes it is in substantial compliance with the standards of the various enforcement agencies. It is unaware of any mining laws or regulations that would materially affect the market price of coal sold by its subsidiaries.
TECO Coal's subsidiaries are subject to various federal, state and local air and water pollution standards in their mining operations. In 2001, approximately $3.7 million was spent on environmental protection and reclamation programs. TECO Coal expects to spend a similar amount in 2002 on these programs.
Coal mining operations are also subject to the Surface Mining Control and Reclamation Act of 1977 which places a charge of $.15 and $.35 on every net ton of underground and surface coal mined, respectively, to create a fund for reclaiming land and water adversely affected by past coal mining. Other provisions establish standards for the control of environmental effects and reclamation of surface coal mining and the surface effects of underground coal mining and requirements for federal and state inspections.
TECO COALBED METHANE
TECO Coalbed Methane participates in the production of natural gas from coalbeds located in Alabama's Black Warrior Basin. TECO Coalbed Methane is the principal investor in three ventures which control, in the aggregate, approximately 100,000 acres of lease holdings. At the end of 2001, TECO Coalbed Methane had interests in 743 wells that were operational and producing gas for sale. These wells are operated by Energen Resources, a unit of Energen Corporation, and, to a much lesser extent, by other third-party operators.
A non-conventional fuels tax credit is available on all production through the year 2002. The tax credit escalates with inflation and could be limited based upon domestic oil prices. In 2001, domestic oil prices did not exceed the $48 per barrel price that would have resulted in this limitation being effective.
All production from these wells is committed for the life of the reserves based on spot prices which are tied to the price of onshore Louisiana gas. From time to time, the company has entered into price swaps to hedge the price variability on this production. See the discussion in the Accounting Standards - -- Accounting for Derivative Instruments and Hedging section. TECO Coalbed Methane's operations are subject to federal, state and local regulations for air emissions and water and waste disposal.
TECO SOLUTIONS
TECO Solutions was formed to support TECO Energy's strategy of offering customers a comprehensive and competitive package of energy services and products with its Florida operations focus. Operating companies under TECO Solutions include TECO BGA, Inc. (formerly Bosek, Gibson and Associates) (TECO BGA), BCH Mechanical, Inc. and its affiliated companies (BCH), Prior Energy Corporation (Prior Energy), TECO Gas Services, Inc. (TECO Gas Services), TECO Properties, TECO Propane Ventures (TPV) and TECO Partners, with total employees of 706 as of Dec. 31, 2001.
TECO BGA is an engineering energy services company headquartered in Tampa. It has 9 offices in Florida and one in California. It provides engineering, construction management and energy services to more than 300 customers, including public schools, universities, health care facilities and other governmental facilities throughout Florida and California. In 2001, BGA increased its presence in the south Florida market with an asset acquisition of an energy services division of AMSI, Inc., and the acquisition of a district cooling business from FPL Energy Services.
BCH is a mechanical contracting firm headquartered in Largo, Florida, and has offices in Cocoa Beach and Ft. Lauderdale. It provides air-conditioning, electrical and plumbing systems, and repair and maintenance services to more than 750 institutional and commercial customers throughout Florida. BCH, one of the leading mechanical contracting firms in Florida, was purchased by TECO Energy in 2000.
In 2001, TECO Solutions acquired Prior Energy. Prior Energy, established in 1987, handles all facets of natural gas energy management services, including natural gas supply management, transportation management, asset management and consulting services. Prior Energy services customers throughout the Southeast Prior Energy is headquartered in Mobile, Alabama.
TECO Gas Services provides gas management and marketing services similar to Prior Energy for large municipal, industrial, commercial and cogeneration facilities. TECO Gas Services has provided gas management services for an increasing customer base as Peoples Gas System makes its "NaturalChoice" option for unbundled service available to more non-residential customers. TECO Gas Services owns no operating assets.
TECO Propane Ventures (TPV) is the subsidiary in which the company's propane business investment is held. This business was formerly known as Peoples Gas Company which was the largest independent propane distributor in Florida. In 2000, TECO Energy entered into an agreement to form US Propane L.P. to combine its Peoples Gas Company propane operations with the propane operations of Atmos Energy Corporation, AGL Resources, Inc. and Piedmont Natural Gas Company, Inc. Later in 2000, US Propane combined with Heritage Holdings, Inc., the general partner of Heritage Propane Partners, L.P. (NYSE:HPG), to create the fourth largest retail propane distributor in the United States.
Under the agreements, US Propane sold its propane business to Heritage Propane for approximately $181 million in cash and limited partnership units in Heritage Propane Partners. US Propane purchased all of the ownership interest of Heritage Holdings, the general partner of Heritage Propane Partners, for $120 million. Upon closing of the transactions, US Propane owned all of the general partner and an approximate 34 percent limited partnership interest in Heritage Propane Partners, the master limited partnership. Interests in the general partner of US Propane are held proportionately among the four companies that created US Propane. TPV has a 38 percent interest in the general partner that manages Heritage Propane Partners. After Heritage Propane Partners issued new equity to the public in 2001, US Propane continued to own all of the general partner interest and its limited partner interest was reduced to 29 percent. TPV owns no operating assets.
Item 2.
Item 2. PROPERTIES.
TECO Energy believes that the physical properties of its operating companies are adequate to carry on their businesses as currently conducted. The properties of Tampa Electric and the subsidiaries of TECO Power Services are generally subject to liens securing long-term debt.
TAMPA ELECTRIC
At Dec. 31, 2001, Tampa Electric had five electric generating plants and four combustion turbine units in service with a total net winter generating capability of 3,899 megawatts, including Big Bend (1,825-MW capability from four coal units), Gannon (1,220-MW capability from six coal units), Hookers Point (90-MW capability from five oil units), Phillips (36-MW capability from two diesel units), Polk (315-MW capability from one integrated gasification combined cycle (IGCC) unit) and four combustion turbine units located at the Big Bend, Polk and Gannon stations (357 MWs). Additionally, Tampa Electric has 56-MW of generating capability from various distributive generation units located at Hookers Point and the City of Tampa. The capability indicated represents the demonstrable dependable load carrying abilities of the generating units during winter peak periods as proven under actual operating conditions. Units at Hookers Point went into service from 1948 to 1955, at Gannon from 1957 to 1967, and at Big Bend from 1970 to 1985. The Polk IGCC unit began commercial operation in September 1996. In 1991, Tampa Electric purchased two power plants (Dinner Lake and Phillips) from the Sebring Utilities Commission (Sebring). Dinner Lake (11-MW capability from one natural gas unit) and Phillips were placed in service by Sebring in 1966 and 1983, respectively. In March 1994, Dinner Lake Station was placed on long-term reserve standby.
Engineering for repowering Gannon Station began in 2000 (see the Environmental Compliance section), and the company anticipates that commercial operation for the first repowered unit will occur by May 1, 2003. The repowering of an additional unit is scheduled to be completed by May 1, 2004. When these units are repowered, the station will be renamed the Bayside Power Station. Total station capacity is expected to increase to about 1,800 megawatts.
Tampa Electric owns 186 substations having an aggregate transformer capacity of 17,216,269 KVA. The transmission system consists of approximately 1,210 pole miles of high voltage transmission lines, and the distribution system consists of 6,987 pole miles of overhead lines and 3,030 trench miles of underground lines. As of Dec. 31, 2001, there were 583,942 meters in service. All of this property is located in Florida.
All plants and important fixed assets are held in fee except that title to some of the properties is subject to easements, leases, contracts, covenants and similar encumbrances and minor defects of a nature common to properties of the size and character of those of Tampa Electric.
Tampa Electric has easements for rights-of-way adequate for the maintenance and operation of its electrical transmission and distribution lines that are not constructed upon public highways, roads and streets. It has the power of eminent domain under Florida law for the acquisition of any such rights-of-way for the operation of transmission and distribution lines. Transmission and distribution lines located in public ways are maintained under franchises or permits.
Tampa Electric has a long-term lease for its office building in downtown Tampa which serves as headquarters for TECO Energy, Tampa Electric and numerous other TECO Energy subsidiaries.
PEOPLES GAS SYSTEM
PGS' distribution system extends throughout the areas it serves in Florida and consists of approximately 13,400 miles of pipe, including approximately 9,000 miles of mains and over 4,400 miles of service lines. Mains and service lines are maintained under rights-of-way, franchises or permits.
PGS' operating divisions are located in fourteen markets throughout Florida. While most of the operations, storage and administrative facilities are owned, a small number are leased.
TECO POWER SERVICES
Hardee Power has a lease for approximately 1,300 acres of land in Hardee and Polk Counties, Florida, on which the Hardee Power Station is located. The lease has a term that runs through 2012 with options to extend the term for up to an additional 20 years.
TM Delmarva, LLC has a 50-percent interest in Commonwealth Chesapeake Company, LLC, which has a lease for approximately 105 acres of land outside of New Church, in Accomack County, Virginia on which the 312-megawatt oil-fired single cycle Commonwealth Chesapeake Power Station is located.
TPS Dell, L.L.C., owns approximately 100 acres in the City of Dell in Mississippi County, Arkansas, on which the 599-megawatt gas-fired combined-cycle electric generation plant is under construction.
TPS McAdams, L.L.C., owns approximately 170 acres of land in McAdams and Sallis, Mississippi, in Attala County, on which the 599-megawatt gas-fired combined cycle electric generation plant is under construction.
TPS Hawaii, Inc. has a 50-percent interest in Enserch/Jones Hamakua Land Partnership, L.L.C. and owns 140 acres in Hawaii on which the Hamakua Energy Project is located. TPS Guatemala One, Inc. has a 96.06-percent interest in TCAE, which owns 7 acres in Guatemala on which the Alborada Power Station is located. TPS San Jose, LDC has a 100-percent ownership in a project entity, CGESJ, which owns 190 acres in Guatemala on which the San Jose Power Station is located.
Frontera Generation L.P. owns 40 acres of land in Hidalgo County, Texas on which the 477-megawatt gas-fired combined cycle electric generation plant is located.
TPS has a 50% ownership interest in TECO-Panda Generating Company, LP, which owns two projects: Union Power Partners LP and Panda Gila River, LP. Union Power Partners owns 330 acres of land in Union County, Arkansas, on which the approximately 2200 MW gas-fired combined-cycle electric generation plant is under construction. Panda Gila River, LP owns approximately 1,099 acres of land in Maricopa County, Arizona, on which the approximately 2145 MW gas-fired combined-cycle electric generation plant is under construction.
TECO TRANSPORT
TECO Bulk Terminal's storage and transfer terminal is on a 1,070-acre site fronting on the Mississippi River, approximately 40 miles south of New Orleans. Bulk Terminal owns 342 of these acres in fee, with the remainder held under long-term leases.
TECO Barge operates a fleet of 18 towboats and over 710 river barges, over 70 percent of which it owns, on the Mississippi, Ohio and Illinois rivers. This includes three towboats and 110 covered river barges chartered in March 1998 under a five-year agreement which provides for the acquisition of these assets at the conclusion of the charter term. TECO Barge owns 15 acres of land fronting on the Ohio River at Metropolis, Illinois on which its operating offices, warehouse and repair facilities are located. Fleeting and repair services for its barges and those of other barge lines are performed at this location. Additionally, TECO Barge performs fleeting and supply activities at leased facilities in Cairo, Illinois.
As of Dec. 31, 2001, 33,500 short ton Ocean Shipping owned and operated a fleet of 12 ocean-going tug/barge units, a ocean-going ship, a 40,900 short ton ocean-going ship, and a 41,100 short ton ocean-going ship, with a combined cargo capacity of over 450,000 tons.
TECO COAL
TECO Coal, through its subsidiaries, controls over 195,000 acres of coal reserves and mining property in Kentucky, Virginia and Tennessee.
Pike-Letcher controls in excess of 50,000 acres in Pike and Letcher Counties, Kentucky. These properties contain estimated proven and probable reserves in excess of 90 million tons.
Premier owns and operates a preparation plant, unit-train loadout facility and synthetic fuel facility in Pike County, Kentucky and conducts surface and deep mining operations of reserves which are leased from Pike-Letcher. Premier does not own any coal reserves.
Clintwood has 68,000 acres of coal reserves held under long-term leases in Pike County, Kentucky and Buchanan County, Virginia. These properties contain estimated proven and probable reserves in excess of 38 million tons. Clintwood owns and operates two rail tipples, coal preparation plants near the mines and a synthetic fuel facility.
Gatliff has 35,000 acres of coal reserves and mining property in Knox and Whitley Counties, Kentucky and Campbell County, Tennessee. Gatliff owns 6,000 acres in fee and leases 29,000 acres under long-term leases. These properties contain estimated proven and probable coal reserves in excess of 10 million tons. This coal, which combines low-sulfur and low-ash fusion temperature characteristics, is found in both deep and surface mines. Gatliff owns and operates a rapid-loading rail tipple and a coal preparation plant near its deep mines.
Bear Branch controls by long-term lease 22,000 acres in Perry and Knott Counties, Kentucky, containing approximately 70 million tons of undeveloped reserves.
Rich Mountain operates a surface mine for Gatliff in Campbell County, Tennessee, and does not own any coal reserves.
Perry County Coal controls 20,000 acres in fee and leases. These properties contain in excess of 23 million tons of
proven reserves. Perry County owns and operates a coal preparation plant and rail tipple facilities.
TECO COALBED METHANE
TECO Coalbed Methane has majority ownership interests and royalty interests in proven gas reserves which at Dec. 31, 2001 was independently estimated to be 167 billion cubic feet for 682 economically feasible wells.
TECO Coalbed Methane's gas production for 2001 was 15.0 billion cubic feet.
Item 3.
Item 3. LEGAL PROCEEDINGS.
None.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matter was submitted during the fourth quarter of 2001 to a vote of TECO Energy's security holders, through the solicitation of proxies or otherwise.
EXECUTIVE OFFICERS OF THE REGISTRANT
Information concerning the current executive officers of TECO Energy is as follows:
Current Positions and Principal Name Age Occupations During Last Five Years ---- --- ----------------------------------
Robert D. Fagan 57 Chairman of the Board, President and Chief Executive Officer, December 1999 to date; President and Chief Executive Officer, May 1999 to December 1999; and prior thereto, President of PP&L Global, Inc. (diversified energy company), Fairfax, Virginia.
William N. Cantrell 49 President of TECO Solutions, September 2000 to date and President of Peoples Gas System June 1997 to date; Director of Peoples Gas Transition Team, January 1997 to June 1997.
Royston K. Eustace 60 Senior Vice President-Business Development, April 1998 to date; and prior thereto, Vice President- Strategic Planning and Business Development.
Gordon L. Gillette 42 Senior Vice President-Finance and Chief Financial Officer, April 2001 to date; Vice President- Finance and Chief Financial Officer, April 1998 to April 2001; Vice President-Regulatory Affairs, April 1997 to April 1998; Vice President- Regulatory and Business Strategy of Tampa Electric Company, April 1996 to April 1997.
Richard Lehfeldt 50 Senior Vice President-External Affairs, November 1999 to date; and prior thereto, Vice President and Assistant General Counsel of Edison Mission Energy (independent power company), Irvine, California.
Richard E. Ludwig 56 President of TECO Power Services Corporation, 1992 to date.
Sheila M. McDevitt 55 Senior Vice President-General Counsel, April 2001 to date; Vice President-General Counsel, January 1999 to April 2001; and prior thereto, Vice President-Assistant General Counsel.
John B. Ramil 46 President of Tampa Electric Company, April 1998 to date; Vice President-Finance and Chief Financial Officer, November 1997 to April 1998; and Vice President-Energy Services and Planning of Tampa Electric Company, November 1994 to November 1997.
D. Jeffrey Rankin 55 President of TECO Transport Corporation, October 1987 to date.
J. J. Shackleford 55 President of TECO Coal, March 1986 to date.
There is no family relationship between any of the persons named above. The term of office of each officer extends to the meeting of the Board of Directors following the next annual meeting of shareholders, scheduled to be held on April 17, 2002, and until such officer's successor is elected and qualified.
PART II
Item 5.
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The following table shows the high, low and closing sale prices for shares of TECO Energy common stock, which is listed on the New York Stock Exchange, and dividends paid per share, per quarter.
1st 2nd 3rd 4th ------- ------- ------- ------- ---- High $32.125 $32.970 $31.650 $28.300 Low $26.100 $28.780 $25.530 $24.750 Close $29.960 $30.500 $27.100 $26.240 Dividend $ 0.335 $ 0.345 $ 0.345 $ 0.345
---- High $20.625 $23.125 $28.750 $33.188 Low $17.250 $19.188 $20.188 $26.563 Close $19.438 $20.063 $28.750 $32.375 Dividend $ 0.325 $ 0.335 $ 0.335 $ 0.335
___________________
The approximate number of shareholders of record of common stock of TECO Energy as of Feb. 28, 2002 was 22,989.
TECO Energy's primary source of funds to pay dividends to its common stockholders is dividends from its operating companies. Tampa Electric's first mortgage bonds and certain long-term debt issues at Peoples Gas System contain provisions that limit the payment of dividends on the common stock of Tampa Electric Company. Substantially all of Tampa Electric Company's retained earnings were available for dividends throughout 2001.
In addition, if TECO Energy exercises its rights to defer payments on its subordinated notes issued in connection with the issuances of trust preferred securities by TECO Capital Trust I and II, TECO Energy will be prohibited from paying cash dividends on its common stock until the unpaid distributions on the subordinated notes are made.
- -------------------------------------------------------------------------------- Item 6.
Item 6. SELECTED FINANCIAL DATA
(1) Includes the effect of charges discussed in Note L, which reduced net income by $19.6 million and earnings per share by $0.15 in 1999. (2) Includes the effect of charges, which reduced net income by $19.6 million and earnings per share by $0.15 in 1998. (3) Includes the effect of merger-related transaction expenses, which reduced net income by $5.3 million and earnings per share by $0.04 in 1997. (4) Dividend paid on TECO Energy common stock.
- -------------------------------------------------------------------------------- Item 7.
Item 7. MANAGEMENT'S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION & RESULTS OF OPERATIONS
The Management's Discussion and Analysis 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 are set forth in the Investment Considerations section. Any forward-looking statement speaks only as of the date on which it was made, and the company undertakes no obligation to update any forward-looking statement to reflect subsequent developments or circumstances other than as may be required by law.
- -------------------------------------------------------------------------------- FINANCIAL SUMMARY
TECO Energy's revenues increased by 15% in 2001 to $2.6 billion; revenues in 2000 increased 16% to $2.3 billion. Basic earnings were $2.26 per share in 2001 compared with $1.99 per share in 2000. Earnings were $1.42 per share in 1999, which included charges of $.11 per share for discontinued operations.
(1) Average shares outstanding reflects the repurchase of 1.6 million shares in 2000 and 5.4 million shares between September and December 31, 1999. (2) Average shares outstanding for 2001 reflects the issuance of 8.625 million shares in March and 3.5 million shares in October. (3) Earnings in 1999 were affected by certain events and adjustments that were unusual in nature and resulted in charges that are not expected to recur in future periods. These charges are described in the Non-Operating Items Impacting Net Income section.
- ------------------------------------------------------------------------------- STRATEGY AND OUTLOOK
TECO Energy's three-pronged business strategy is: to focus on its Florida operations, which include Tampa Electric, Peoples Gas System (PGS) and the Florida energy services businesses at TECO Solutions; to grow its TECO Power Services (TPS) independent power operations; and to use the returns of its family of other profitable unregulated businesses to continue its growth.
Execution of this strategy has allowed TECO Energy to achieve earnings per share growth of 14 percent in 2001 and 18 percent in 2000 from continuing operations, excluding charges in 1999. In January 2002, management stated that 2002 is a transition year with the focus on completing the four independent power projects currently under construction at TPS and the first phase of the Gannon to Bayside repowering project at Tampa Electric. It indicated at that time that earnings per share growth for 2002, targeted at 5 percent, is expected to be driven by continued growth from the Florida operations, a return to more normal shipping patterns at TECO Transport, higher earnings from improved pricing and higher production at TECO Coal, and a full year of operations from capacity additions during 2001 at TPS.
TECO Energy benefits from deriving the majority of net income from its regulated businesses, Tampa Electric and PGS, operating in one of the best utility markets in the nation. Growth is expected in Florida in 2002 because the State's economy with its small industrial base is not expected to be impacted by the economic slowdown to the same degree as some other areas of the country that are based on manufacturing. Growth is expected in the residential and commercial sectors in 2002 and beyond.
In 2003, a significant earnings driver will be the four new independent power projects that TPS announced in late 2000 which are expected to be placed in service in 2003. These projects have increased the number of net megawatts operating or under construction from approximately 1,000 megawatts at the end of 1999 to almost 6,600 megawatts at the end of 2001.
In 2001, future wholesale power prices declined significantly in markets across the country due to the combination of the U.S. economic slowdown and the amount of new generating capacity under construction and expected to come online in 2002 and 2003. The outlook for weaker earnings from new independent power projects, however, has caused some developers to cancel or delay projects. While future wholesale power prices have declined, TPS expects to enter into negotiated contracts for much of the output of its facilities at higher prices, reflecting the value-added services it can provide. TECO Energy remains committed to the completion of the four projects under construction by TPS. See Operating Results - TECO Power Services for a current schedule of in-service dates for these projects.
In light of the capital requirements for committed regulated and unregulated projects and the accelerated project equity commitments for the Union and Gila River projects under the bank financing plan at TPS (see Enron Exposure section), TECO Energy has taken several steps to strengthen its balance sheet. During 2001, the company issued new common equity on two occasions totaling $331 million of proceeds. In January 2002, the company issued $449 million of mandatorily convertible equity units which will convert to TECO Energy common shares in January 2005. (See Financing Activity section.) In addition, the company has reduced its capital expenditure forecast for 2002 through 2004 by approximately $700 million, primarily by delaying for an extended period generation projects that are not yet under construction for TPS and Tampa Electric, including the Bayside Units 3 and 4 repowering projects announced in the fall of 2001. Resumption of work on those projects will be evaluated periodically as market conditions evolve.
Near-term expectations for the various operating companies are summarized below.
Tampa Electric and PGS are positioned to see growth in sales and earnings above the estimated 2.3 percent and 5 percent rates of customer growth, respectively. Earnings growth in 2002 is expected to be driven by higher AFUDC associated with the Gannon to Bayside repowering project and energy sales growth at Tampa Electric, which is expected to exceed customer growth due to a more favorable customer mix.
At TPS in 2002, growth is expected from a full-year of operations of both the Frontera Power Station in Texas and Phase II of the Commonwealth Chesapeake Power Station in Virginia. In addition, TPS' 2001 results included a $6.1 million charge associated with the termination of its investment in EGI. (See Operating Results - TECO Power Services section.)
At TECO Transport, earnings growth in 2002 is expected from increased phosphate shipments and a return to a more normal pattern for U.S. government grain shipments. Long-term growth is expected from increased asset utilization, particularly at TECO Barge Line (formerly known as Mid-South Towing), and asset additions at both TECO Ocean Shipping (formerly known as Gulfcoast Transit) and TECO Barge Line.
TECO Coal expects to benefit primarily from improved prices for steam and metallurgical coals and modestly higher production of synthetic fuel and coal in 2002. Production of synthetic fuel at TECO Coal qualifies for Section 29 tax credits for non-conventional fuel production.
The company expects higher borrowing levels in 2002 associated primarily with the TPS generation projects and the Gannon to Bayside repowering project at Tampa Electric.
The above forward-looking statements are subject to many factors that could cause actual results and conditions to differ materially from those projected in these statements. (See the Investment Considerations section.)
- ------------------------------------------------------------------------------- CRITICAL ACCOUNTING POLICIES
Management's Discussion and Analysis of Financial Condition & Results of Operations are based on TECO Energy's consolidated financial statements, which have been prepared in accordance with United States generally accepted accounting principles. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. These estimates and assumptions are based on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and judgments under different assumptions or conditions.
The following critical accounting policies, among others discussed throughout the Management's Discussion and Analysis and the Notes to the Consolidated Financial Statements, involve the more significant estimates and judgments used in the preparation of TECO Energy's consolidated financial statements.
Revenue Recognition
TECO Energy and its subsidiaries recognize revenues in accordance with the Securities and Exchange Commission's Staff Accounting Bulletin (SAB) 101, Revenue Recognition in Financial Statements. Generally, TECO Energy and its subsidiaries recognize revenues when earned, and the risks and rewards of ownership have transferred to the buyer.
The regulated utilities' retail business and the prices charged to customers are regulated by the Florida Public Service Commission (FPSC); Tampa Electric's wholesale business is regulated by the Federal Energy Regulatory Commission (FERC) (see the Utility Regulation section). As a result, the regulated utilities qualify for the application of Financial Accounting Standard (FAS) 71, Accounting for the Effects of Certain Types of Regulation. This statement recognizes that the rate actions of a regulator can provide reasonable assurance of the existence of an asset and requires the capitalization of incurred costs that would otherwise be charged to expense where it is probable that future revenue will be provided to recover these costs. The impact of FAS 71 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. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates.
Deferred Income Taxes
TECO Energy uses the liability method in the measurement of deferred income taxes. Under the liability method, the company estimates its current tax exposure and assesses the temporary differences resulting from differing treatment of items, such as depreciation, for financial statement and tax purposes. These differences are reported as deferred taxes measured at current rates in the consolidated financial statements. The company then assesses the likelihood that deferred tax assets will be recovered from future taxable income and to the extent recovery of some portion or all of the deferred tax asset is not believed to be likely, establishes a valuation allowance.
At Dec. 31, 2001, TECO Energy had deferred income tax assets of $242 million attributable primarily to alternative minimum tax credit carryover of Sec. 29 non-conventional fuel credits and property related items. The carrying value of the Company's deferred income tax assets assumes that the Company will be able to realize this asset as an offset to future income taxes payable. The Company periodically reviews its deferred income tax assets and, to the extent it determines that recovery is not likely, increases its valuation reserve as a charge to income.
Derivative Instruments and Hedging
Effective Jan. 1, 2001, the company adopted FAS 133, Accounting for Derivative Instruments and Hedging Activities. As discussed in the Accounting Standards section, FAS 133 requires the company to recognize derivatives as either assets or liabilities in the financial statements, to measure these instruments at fair value, and to reflect the changes in fair value of those instruments as components of comprehensive income or in net income. The determination of fair value is dependent upon certain assumptions and judgments. The methods used to determine fair value are also discussed in the Accounting Standards section. The Company's fair value determination assumptions are primarily based on regulated exchange based prices.
In addition, the company has certain derivative transactions that are marked-to-market under the Financial Accounting Standards Board's (FASB) Emerging Issues Task Force (EITF) release Issue 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. These transactions are also discussed in the Accounting Standards section.
Impairment Testing
TECO Energy and its subsidiaries periodically assess whether there has been a permanent impairment of its long-lived assets in accordance with FAS 121, Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of, and beginning in 2002, with FAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Long-lived assets are tested for impairment periodically using a non-discounted cash flow test. Tests are also performed when industry, regulatory or other significant changes cause a change in the projected level of income or cash flow to be earned from an asset.
In June 2001, the Financial Accounting Standards Board issued FAS 142, Goodwill and Other Intangible Assets. With the adoption of FAS 142, effective Jan. 1, 2002, goodwill is no longer subject to amortization, however goodwill and other intangible assets are subject to annual assessments for impairment by applying fair-value-based tests.
FAS 144 and FAS 142 are discussed in the Accounting Standards section.
As discussed below under Enron Exposure, certain of the Company's assets are affected by the Enron bankruptcy. The Company does not presently anticipate any material asset impairment charges as a result of its Enron exposure, but subsequent developments could affect this judgment.
Unconsolidated Affiliates
The Company has investments in unconsolidated affiliates that are accounted for using the equity method of accounting as discussed in Note A to the Consolidated Financial Statements. The equity method of accounting is used to account for investments in partnership arrangements in which TECO Energy or its subsidiary companies do not have a majority ownership or exercise control. Future changes in accounting standards regarding consolidations or changes in the nature of the Company's investment in the unconsolidated affiliates could result in these investments being consolidated, with resulting impact on the Company's recorded assets and liabilities, and on its results of operations.
OPERATING RESULTS
TECO Energy's Net Income
Net income in 2001 was $303.7 million, up 21 percent from $250.9 million in 2000. These results reflect continued customer growth and increased energy usage in the Florida operations, higher AFUDC at Tampa Electric, an 18 percent increase in net income at TPS from the new generation projects acquired or brought on line in 2000 and 2001 and improved results from the Guatemalan operations, higher average gas price at TECO Coalbed Methane, and higher conventional coal production and prices and increased synthetic fuel production at TECO Coal. These improvements were partially offset by higher interest expense associated with increased borrowing levels.
Net income in 2000 was $250.9 million, up 14 percent from $220.5 million from continuing operations and before charges in 1999. These results reflect continued customer growth and increased energy usage in the Florida operations, a more than doubling of net income at TPS from the new generation projects brought on line in late 1999 and 2000 and improved results from the Guatemalan distribution utility, good operating conditions and strong markets at TECO Transport, and the addition of synthetic fuel production at TECO Coal. These improvements were partially offset by higher interest expense associated with increased borrowing levels.
The following table shows the unconsolidated revenues, net income and earnings per share contribution from continuing operations of the significant business segments, excluding charges in 1999 described in the Non-Operating Items Impacting Net Income section. (For additional detail, refer to the Notes to Consolidated Financial Statements -Footnote K, Segment Information.)
(1) Includes $11.9 million of deferred revenues. This amount is before the $7.9- million deferred revenue benefit recognized under the regulatory agreement related to the charges for tax settlements, described in the Non-Operating Items Impacting Net Income section. (2) From continuing operations, excluding the charges described in the Non- Operating Items Impacting Net Income section. (3) Beginning in 2001, segment net income was reported on a basis that included internally allocated financing costs. Prior period net income has been restated to reflect estimated internally allocated financing costs that would have been attributable to such prior periods. Internally allocated finance costs for 2001, 2000 and 1999 were at pretax rates of 7%, 6.75% and 6.75%, respectively, based on the average investment in each subsidiary.
- -------------------------------------------------------------------------------- TAMPA ELECTRIC - ELECTRIC OPERATIONS
Tampa Electric Results Tampa Electric's net income increased almost 7 percent in 2001, reflecting good customer growth, slightly higher residential and commercial per-customer energy usage, and a favorable customer mix partially offset by higher operations, maintenance and depreciation expenses. In addition, allowance for funds used during construction (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 the equity funds used for construction), primarily from the Gannon to Bayside Units 1 and 2 repowering project increased to $9.2 million compared with $2.3 million in 2000. Tampa Electric's net income increased 4 percent in 2000, reflecting good customer growth, higher per-customer energy usage, a favorable customer mix and more normal weather, partially offset by higher operations and maintenance expense. In July 2000, Tampa Electric placed its new, 180-megawatt combustion turbine Polk Unit 2 in service.
- ------------------------------------------------------------------------------- SUMMARY OF OPERATING RESULTS - ------------------------------------------------------------------------------- (millions) 2001 Change 2000 Change 1999 - ------------------------------------------------------------------------------- Revenues $1,412.7 4.3% $1,353.8 12.8% $ 1,199.8 (1) Operating expenses 1,124.6 6.1% 1,060.3 13.3% 935.9 - ------------------------------------------------------------------------------- Operating income $ 288.1 -1.9% $ 293.5 11.2% $ 263.9 - ------------------------------------------------------------------------------- Net Income $ 154.0 6.6% $ 144.5 4.1% $ 138.8 - -------------------------------------------------------------------------------
(1) Includes $11.9 million of deferred revenues. This amount is before the $7.9- million deferred revenue benefit recognized under the regulatory agreements in place at that time related to the charge for tax settlements, described in the Non-Operating Items Impacting Net Income section.
Tampa Electric Operating Revenues The economy in Tampa Electric's service area continued to grow in 2001, with increased employment from the local economy aided by corporate relocations and expansions. The Tampa metropolitan area's employment grew 2 percent in 2001, ranking it first in job growth among metropolitan areas in a study by the U.S. Department of Labor. The economy slowed somewhat in the second half of the year as the U.S. economic slowdown impacted the area. The unemployment rate rose to 4.0 percent in December 2001, from a low of 2.4 percent in December 2000, compared to 5.7 percent for the State of Florida and 5.8 percent for the nation. This trend was accelerated by a marked slowdown in tourism-related businesses following September 11th. The impact on Tampa Electric's sales was minimal, because the areas served are not as sensitive to changes in the tourist industry as some other areas of the state. Retail megawatt sales rose 2 percent in 2001 primarily from increased residential and commercial sales from higher numbers of customers and slightly higher per-customer usage. Combined residential and commercial customer growth was 2.8 percent with combined energy usage growing 2.9 percent. Sales to the low-margin industrial customers in the phosphate industry declined 10.9 percent due to temporary facility closures during the year and the permanent closure of one facility. The phosphate industry experienced its second year of a worldwide slowdown due to over capacity and reduced usage. Late in the year there was an increase in demand from these customers as demand for phosphate fertilizers increased overseas and some previously idled facilities were returned to service. According to phosphate industry sources, the market is expected to improve modestly in 2002 with stable domestic prices and increased fertilizer demand primarily in China. Revenues from phosphate sales represented slightly less than 3 percent of base revenues in 2001 and 2000. Non-phosphate industrial sales increased in 2001 and 2000, primarily reflecting continued economic growth in the area. Sales to other utilities for resale declined in 2001 primarily as a result of lower coal-fired
generating unit availability due to higher planned maintenance outages. Tampa Electric's 2000 operating revenues increased 13 percent from 3 percent customer growth, more normal winter weather and increased per-customer energy usage. The customer mix continued to shift toward higher margin residential and commercial customers in 2000. In 2000, combined residential and commercial megawatt sales increased 5 percent from the addition of more the 16,000 new customers and a return to more normal weather. Based on expected growth reflecting continued population increases and business expansion, Tampa Electric expects retail energy sales growth of approximately 2.6 percent annually over the next five years, with combined energy sales growth in the residential and commercial sectors of more than 3 percent annually. Retail demand growth is expected to average 100 megawatts of capacity per year for the next five years. These growth projections assume continued local area economic growth even in the current national economic climate, normal weather and certain other factors. (See the Investment Considerations section.)
- -------------------------------------------------------------------------------- MEGAWATT-HOUR SALES - -------------------------------------------------------------------------------- (thousands) 2001 Change 2000 Change 1999 - -------------------------------------------------------------------------------- Residential 7,594 3.1% 7,369 5.8% 6,967 Commercial 5,685 2.6% 5,541 3.8% 5,336 Industrial 2,329 -2.6% 2,390 7.5% 2,224 Other 1,368 2.2% 1,338 4.7% 1,278 - -------------------------------------------------------------------------------- Total retail 16,976 2.0% 16,638 5.3% 15,805 Sales for resale 1,499 -41.5% 2,564 18.7% 2,160 - -------------------------------------------------------------------------------- Total energy sold 18,475 -3.8% 19,202 6.9% 17,965 - -------------------------------------------------------------------------------- Retail customers (average) 575.8 2.8% 560.1 3.0% 543.7 - --------------------------------------------------------------------------------
Tampa Electric Operating Expense Operating expenses increased 6 percent in 2001, reflecting higher fuel costs from higher coal prices, increased purchased power costs due to lower unit availability, higher maintenance expenses associated with increased planned outages on coal-fired generating units, and higher depreciation from normal plant additions to serve increased numbers of customers. Operating expenses increased 13 percent in 2000 reflecting increased costs associated with the Big Bend Units 1 and 2 flue gas desulfurization system placed in service in December 1999, the expiration of the U.S. Department of Energy (DOE) credits for Polk Unit 1 at the end of 1999, increased generating system maintenance to improve summer availability and costs associated with organizational streamlining. Costs associated with the flue gas desulfurization system are recovered through the Environmental Cost Recovery Clause (ECRC). (See the Utility Regulation section.) Non-fuel operations and maintenance expenses in 2002 are expected to increase at a rate slightly above inflation primarily due to increased costs associated with health care benefits.
- -------------------------------------------------------------------------------- OPERATING EXPENSES - -------------------------------------------------------------------------------- (millions) 2001 Change 2000 Change 1999 - ------------------------------------------------------------------------------- Other operating expenses $ 190.7 1.3% $188.3 15.1% $ 163.6 Maintenance 99.5 3.5% 96.1 10.3% 87.1 Depreciation 173.4 7.3% 161.6 9.5% 147.6 Taxes, other than income 104.8 6.2% 98.7 -0.1% 98.8 - ------------------------------------------------------------------------------- Non-fuel operating expenses 568.4 4.4% 544.7 9.6% 497.1 - ------------------------------------------------------------------------------- Fuel 346.5 7.1% 323.5 6.4% 304.0 Purchased power 209.7 9.2% 192.1 42.5% 134.8 - ------------------------------------------------------------------------------- Total fuel expense 556.2 7.9% 515.6 17.5% 438.8 - ------------------------------------------------------------------------------- Total operating expenses $1,124.6 6.1% $1,060.3 13.3% $ 935.9 - -------------------------------------------------------------------------------
Depreciation expense increased in both 2001 and 2000 reflecting normal plant additions to serve the growing customer base and maintain generating system reliability. In addition, Polk Unit 2, a 180-megawatt combustion turbine placed in service in mid-2000, accelerated depreciation associated with coal-related assets at the Gannon Station, and a flue gas desulfurization system added in 1999 to serve Big Bend Units 1 and 2 have all increased depreciation. Depreciation expense is projected to increase in 2002, as well as in the future from normal plant additions, an additional combustion turbine at the Polk Power Station in 2002 and the first phase of the Gannon repowering project entering service in 2003. (See the Environmental Compliance section.) Fuel costs increased 7 percent in 2001 reflecting primarily increased coal costs during the year. Coal prices increased early in the year, as did oil and natural gas. Coal prices have since dropped from the peak prices experienced in the first quarter but remain above 2000 levels. Average coal costs, on a cents-per-million Btu basis, increased 7 percent in 2001 after a slight decrease in 2000. Fuel costs increased 6 percent in 2000 reflecting increased generation and increased use of more expensive oil and natural gas at Polk Unit 2, Hookers Point and combustion turbines at the Big Bend Power Station. Purchased power expense increased in 2001 due to lower unit availability, primarily the result of planned maintenance outages on base load generating units and unplanned outages during peak load periods. Purchased power expense increased in 2000 due to lower unit availability, primarily the result of a generator failure at Gannon Unit 6. Nearly all of Tampa Electric's generation in the last three years has been from coal, and the fuel mix is expected to continue to be substantially comprised of coal until 2003 when the first of two repowered units at Bayside is scheduled to begin operating on natural gas. See the Environmental Compliance section. On a total energy supply basis, company generation accounted for 84 percent, 92 percent and 83 percent of the total system energy requirements in 2001, 2000 and 1999, respectively.
________________________________________________________________________________ PEOPLES GAS SYSTEM Peoples Gas System is the largest investor-owned gas distribution utility in Florida, with about 70 percent of the investor-owned local distribution company market. It serves more than 270,000 customers in all of the major metropolitan areas of Florida. PGS net income rose 6 percent in 2001 from 4 percent customer growth and increased gas transported for off-system sales. The high cost of gas earlier in 2001 had a negative impact on sales to larger interruptible and power generation customers, many of whom have the ability to switch to alternative fuels or to alter consumption patterns. In the second half of the year, the price differential between natural gas and alternative fuels once again favored natural gas, causing customers to return to natural gas as alternative fuel inventories are exhausted and contractual commitments expire. PGS achieved net income growth of 10 percent in 2000 from customer growth, increased gas transported for off-system sales to electric power generators and interruptible customers and colder weather late in the year. Historically the natural gas market in Florida has been underserved with the lowest market penetration in the southeastern U.S. PGS is expanding its gas distribution system into areas of Florida not previously served and within areas currently served.
- -------------------------------------------------------------------------------- SUMMARY OF OPERATING RESULTS - -------------------------------------------------------------------------------- (millions) 2001 Change 2000 Change 1999 - -------------------------------------------------------------------------------- Revenues $ 352.9 12.2% $ 314.5 24.9% $ 251.7 Cost of gas sold 186.4 18.7% 157.0 45.8% 107.7 Operating expenses 115.4 4.4% 110.5 9.6% 100.8 - -------------------------------------------------------------------------------- Operating income $ 51.1 8.7% $ 47.0 8.8% $ 43.2 - -------------------------------------------------------------------------------- Net Income $ 23.1 6.0% $ 21.8 10.1% 19.8 - --------------------------------------------------------------------------------
Therms sold (millions) - by customer segment Residential 58.8 2.1% 57.6 10.6% 52.1 Commercial 308.9 5.8% 292.1 6.8% 273.5 Industrial 346.5 -7.4% 374.1 12.7% 331.9 Power generation 403.5 -3.6% 418.6 3.3% 405.2 - -------------------------------------------------------------------------------- Total 1,117.7 -2.2% 1,142.4 7.5% 1,062.7 - --------------------------------------------------------------------------------
Therms sold (millions) - by sales type System supply 292.2 -8.9% 320.6 6.9% 300.0 Transportation 825.5 0.4% 821.8 7.7% 762.7 - -------------------------------------------------------------------------------- Total 1,117.7 -2.2% 1,142.4 7.5% 1,062.7 - -------------------------------------------------------------------------------- Customers (thousands) - average 266.6 4.1% 256.2 3.9% 246.7 - --------------------------------------------------------------------------------
Residential and commercial therm sales increased again in 2001 from more than 4 percent residential customer growth and increased per-customer usage. Commercial therm sales increased primarily from increased per-customer use. Residential therm sales increased in 2000, the result of 4 percent residential customer growth and cold weather late in the year. Commercial therm sales increased in 2000 reflecting good customer growth and a strong economy. The actual cost of gas and upstream transportation purchased and resold to end-use customers is recovered through a Purchased Gas Adjustment (PGA) clause approved by the Florida Public Service Commission. The company files for mid-period adjustments to the PGA in times of gas price volatility, as was experienced in 2000 and early 2001. In November 2000, PGS instituted its "NaturalChoice" program, which unbundles gas services for all non-residential customers, affording these customers the opportunity to purchase the commodity gas from any provider. The net result of this unbundling is a shift from commodity sales to transportation sales. Because commodity sales are included in operating revenues at the cost of the gas on a pass-through basis, there is no net financial impact to the company of transportation-only sales. At year-end 2001, 8,000 customers had elected to take service under this program. Because PGS earns margins on the distribution of gas, but not on the commodity itself, this program is not expected to negatively impact PGS' results. Operation and maintenance expenses were essentially unchanged from 2000 levels, while depreciation expense increased 8 percent, in line with the increased capital expenditures that have been made over the past several years to expand the system. Operating expenses increased in 2000, in line with customer growth and system expansion. PGS expects to invest an average of $60 million for each of the next five years to grow the business and maintain system reliability. PGS expects increases in sales volumes and corresponding revenues in 2002, and continued customer additions and related revenues from the expansion efforts throughout the state. These growth projections assume continued local area economic growth, normal weather and other factors. (See the Investment Considerations section.)
- -------------------------------------------------------------------------------- TECO POWER SERVICES Net income increased 18 percent in 2001 to $26.9 million from higher earnings from the Hamakua and Commonwealth Chesapeake stations, the Guatemalan generating stations and higher returns on TPS's investment in the Panda Texas Independent Energy (TIE) projects. The improved operating performance was partially offset by weak results at the Frontera Station, which was acquired in 2001, due to low power prices in the Texas market, increased financing costs, higher development costs and a $6.1-million after-tax valuation reserve recognized in the sale of TPS' minority interest in Energia Global International, Ltd. (EGI), which owns small generating projects in Central America. In 2000, TPS net income of $22.8 million was more than double the 1999 level driven by new investments, projects placed in commercial operation in 2000, improved results at Empresa Electrica de Guatemala, S.A. (EEGSA), the Guatemalan distribution utility in which TPS acquired a 24 percent interest in 1998, and increased earnings from the expansion of the Hardee Power Station. In 2000, TPS recorded $5.4 million of other income related to an insurance claim settlement at the San Jose Power Station for mechanical damage and loss of business from a turbine oil system failure, and other turbine problems. The 120-megawatt San Jose Power Station began commercial operation in January 2000. TPS increased its ownership interest in this project to 67 percent in December 1999 and acquired the remaining ownership interest in February 2000. TPS has a 15-year power supply agreement with EEGSA. The 75-megawatt expansion of the Hardee Station in Florida, began commercial operation in May 2000, and is supplying power to Tampa Electric under a long-term contract. The first phase of the Hamakua project in Hawaii began commercial operation in August 2000 and the final phase began commercial operation in December 2000. The 135-megawatt first phase of the 312-megawatt Commonwealth Chesapeake electric generating facility in Virginia began commercial operation in September 2000. The final phase of this project began commercial service in August 2001. The Enron bankruptcy creates uncertainty for four TPS generation projects because an Enron subsidiary, NEPCO, is the engineering, procurement and construction (EPC) contractor for the four projects. NEPCO has not filed for bankruptcy, and has continued construction and engineering work on these power plants and currently the construction of all four plants is on schedule. (See Enron Exposure section.)
(1) Currently in the form of a loan, represents the potential economic interest estimated at 75 percent of Panda's 50-percent interest in these projects.
(2) Based on the effect of the preferred return, estimated at 75 percent over the life of the project.
Construction and Development Activities In 2000, TPS refocused its development efforts on domestic energy projects. During the second half of 2000 and early 2001, TPS announced seven major projects representing a net ownership interest increase of almost 5,700 megawatts of new capacity operating or under construction. (See the Investment Considerations section.) TPS has projects operating or under construction with a net ownership interest in almost 6,600 megawatts. Upon completion, the domestic projects will provide TPS with the opportunity to sell wholesale power in 18 states, ranging from Hawaii to Florida to Virginia. The new projects are in historically high- growth areas, with good access to fuel supply and electric transmission systems. In September 2000, TPS announced a $93-million investment in the form of a loan related to Panda Energy International's (Panda) Texas Independent Energy Projects (TIE). This investment, under certain circumstances, gives TPS an opportunity in the future for an effective economic interest estimated at 75 percent, of Panda's 50-percent interest in these projects (approximately 1,000 MW). The interest earned on the loan to TIE contributed to fourth quarter earnings in 2000 and full-year earnings in 2001. Under certain circumstances, among which are additional capital investments by TPS, this loan could give TPS an ownership interest in these projects in late 2002. In October 2000, TPS announced the acquisition of two 599-megawatt, natural gas-fired, combined-cycle projects, Dell and McAdams located in Arkansas and Mississippi, respectively. Construction commenced on these projects in 2001 and is continuing. These projects are now expected to begin commercial operation in the first quarter of 2003. The Dell project was originally scheduled to be placed in service in the fourth quarter of 2002, but a delay in the completion of a natural gas compressor station by the pipeline owner has moved the completion date to early in 2003. The McAdams project was rescheduled to match the in-service date of the Dell project. These projects are being constructed by NEPCO and were in the process of being financed with non-recourse project financing at the time of the Enron bankruptcy. The financing was delayed pending resolution of the Union and Gila River project funding. (See Enron Exposure section.) Financing activities for these projects have resumed. TECO Energy has continued to fund the construction since commencement. In November 2000, TPS announced a 50/50 joint venture with Panda to build, own and operate the 2,200-megawatt Union plant (formerly known as El Dorado) in Arkansas and the 2,145-megawatt Gila River Power Station in Arizona. TPS earns a preferred return on the investment in these projects, which gives it an effective economic interest estimated at 75 percent over the life of the project. Construction commenced on these projects in 2001, and remains on schedule. Each of these projects will begin commercial operation in four phases, beginning with the first 550-megawatt phase of Union expected in late 2002 and ending with the 540-megawatt final phase of Gila River expected in the summer of 2003. The TPS investment in these projects was $624 million at Dec. 31, 2001, and at commercial operation it is expected to be $1.1 billion. During the suspension of bank construction funding caused by the Enron Bankruptcy, TECO Energy continued to fund the construction, which has continued uninterrupted. NEPCO has not filed for bankruptcy and has continued to perform under the contracts. (See Enron Exposure Section.) The bank construction funding of these two plants resumed in mid-January 2002. In February 2002, the TPS and Panda affiliates that comprise the joint venture that owns the Union and Gila River projects entered into an arrangement providing for TPS to purchase and for Panda to sell Panda's interest in the joint venture in 2007 for $60 million. Panda has the right to cancel the purchase arrangement by paying TPS $20 million, or a lesser amount under certain circumstances. The purchase arrangement can result in TPS's purchase of the interest prior to 2007 under certain circumstances, including Panda's default under a bank loan made to Panda using the purchase arrangement as collateral. In March 2001, TPS acquired American Electric Power's (AEP) Frontera Power Station located near McAllen, Texas. This 477-megawatt, natural gas-fired, combined-cycle plant, originally developed by CSW Energy (CSW), began combined- cycle operation in May 2000 and has a 150-megawatt transmission connection to the Federal Electricity Commission of Mexico (CFE). In February 1999, TPS formed an alliance with Energia Global International, Ltd. (EGI), a company with energy interests in Latin America. TPS initially committed $25 million in the form of a loan, which became an equity interest at the end of 2000. The interest income from the EGI loan contributed to TPS' net income in 1999 and 2000. TPS made an additional loan of $20 million in 2000. In the first quarter 2001, TPS recognized a $6.1 million after-tax charge as part of the sale of its interest in EGI. The sale was completed, and TPS no longer has any ownership interest in EGI.
Energy Markets The power plants that TPS is operating and constructing are located in markets that have a history of high load growth. In 2001, the general U. S. economic slowdown and the perception that excess generating capacity is being built in many of these markets caused future wholesale power prices to drop significantly. Current forward curve prices for the 2003 period would make the 2003 returns from many of the projects under construction by TPS and others unattractive. The current forward curve prices represent prices for spot-market power that a seller would expect to receive if future capacity was sold today and do not represent the prices that TPS believes would be paid under negotiated contracts where capacity payments and ancillary services are included and there is a premium for physical assets. In addition, spot markets setting prices for power a year in advance of the time of sale are not liquid markets and do not necessarily provide accurate indications of future power prices. TPS' strategy for selling the output of these plants is to enter into three to five year contracts with load serving entities, or ultimate customers where it is allowed, for up to 50 percent of the
output of the plants. TPS expects to contract another 25 percent of the output in the shorter term (less than one year market) with the remaining 25 percent sold in the spot market. TPS has retained experienced power marketers, such as Mirant for Commonwealth Chesapeake and Aquila for the Dell and McAdams stations, to market the 25 percent of the output planned for the spot market. To optimize the value of the generating assets TPS in 2001, activated its TECO EnergySource (TES) subsidiary to enter into power marketing and fuel procurement transactions. TES is actively seeking contracts with purchasers for the output from the four projects under construction and the Frontera Station. TES expects to enter into contracts to procure the fuel for the generating plants and sell the fuel to them, and it expects to enter into contracts to purchase the output from the generating plants for resale to wholesale power purchasers. TES will present a single face to the energy markets for TPS. TES expects to provide these services by entering into contracts to purchase or supply electricity and natural gas, primarily at specified delivery points and specified future dates (i.e., fixed-price forward sales and purchase contracts). In some cases TES will utilize financial instruments such as futures and options contracts traded on the NYMEX and swaps and other types of financial instruments traded in the over-the-counter markets to manage its exposure to electricity and natural gas price fluctuations. The use of these types of contracts is expected to allow TES to manage and hedge its contractual commitments and to reduce its exposure relative to the volatility of cash market prices. TES activities utilizing futures, options, swaps or other financial instruments was minimal in 2001 due to the start up nature of the business. TES will normally balance its fixed-price physical and financial fuel purchase and energy sales contracts in terms of contract volumes and the timing of performance and delivery obligations. Net open positions may exist due to the origination of new transactions. When net open positions exist, TES will be exposed to fluctuating market prices. In addition to price risk, credit risk is inherent in TES' risk management activities. The trading and marketing business may be exposed to counterparty credit risk from a counterparty not fulfilling its obligations. Credit policies with regard to counterparties attempt to limit overall credit risk. The company's credit procedures include a thorough review of potential counterparties' financial position, collateral requirements under certain circumstances, monitoring net exposure to each counterparty and the use of standardized agreements. The credit and overall risk management policies are monitored and administered by a function within TECO Energy independent of the trading and marketing activities. Significant factors that could influence results at TPS include successful financing, construction of its new projects, weather, domestic economic conditions and commodity price changes. (See the Investment Considerations section.)
________________________________________________________________________________ TECO TRANSPORT Net income declined 6 percent in 2001. Increased phosphate and other product shipments, higher revenue from outside services at TECO Barge Line, and lower fuel prices were more than offset by lower U.S. government grain program shipments, higher costs primarily related to depreciation, and lower shipments of steel-related products handled by TECO Bulk Terminal (formerly known as Electro-Coal Transfer L.L.C.). Results for 2000 included an after-tax gain of approximately $1.5 million associated with the disposition of an ocean-going asset. Net income at TECO Transport increased 11 percent in 2000 reflecting a strong export grain market, higher levels of coal moved for Tampa Electric, increased movements of steel-related products northbound on the river systems and a gain on the disposition of an ocean-going asset. Partially offsetting these improvements were higher fuel prices, continued weakness in the export coal market and lower phosphate shipments, as producers curtailed production to bring supply and demand in balance. In 2001, TECO Transport's ocean-going subsidiary, TECO Ocean Shipping (TOS) acquired a 40,000-ton geared vessel at auction at a price well below the replacement value. The ship was reflagged with the U.S. flag and is now in U.S. coastwise trade serving customers along the Gulf, East and West coasts. The ship, which entered service in the summer of 2001, contributed to 2001 results and is expected to add to earnings in 2002. The ship's speed, reduced weather sensitivity and cargo handling flexibility from the on-board cranes are expected to enhance TOS' operation. TECO Transport expects a return to more normal patterns of U.S. government grain shipments and a modest improvement in phosphate product shipment volumes in 2002. In 2001, a delay of several months was experienced in the start of the U.S. government grain programs due to the change of the administration in Washington D.C. following the 2000 presidential election. Northbound river shipments of steel-related products are not expected to improve until the U.S. economy improves. In the meantime, TECO Transport expects to move increased volumes of fertilizers, imported coal and petroleum coke northbound on the river system. The phosphate fertilizer industry continued to experience worldwide oversupply and low prices through the first half of 2001. By the second half of 2001, demand for phosphate products had improved and shipments of raw phosphate rock between Tampa and Louisiana resumed. The outlook is for stable phosphate prices and demand in 2002. TECO Transport expects to continue diversifying into new markets and cargoes. Future growth at TECO Transport is dependent on higher asset utilization, particularly at TECO Barge Line with north-and southbound cargoes, and asset additions at both the river and ocean-going businesses. Significant factors that could influence results include weather, bulk commodity prices, fuel prices and domestic and international economic conditions. (See the Investment Considerations section.)
________________________________________________________________________________ TECO COAL Net income increased 76 percent in 2001, driven primarily by better margins and higher synthetic fuel (synfuel) production, increased coal production from Perry County Coal, Inc.'s mining facilities acquired in late 2000, and higher metallurgical coal prices in the second half of the year. 2001 was the first full year of production for the synfuel production facilities which entered service late in the second quarter of 2000. Production of synthetic fuel at TECO Coal qualifies for Section 29 tax credits for non-conventional fuel production. Production of synfuel increased to 3.2 million tons in 2001 from more than 1.9 million tons in 2000. The net benefit increased to approximately $56 million in 2001 from approximately $30 million in 2000. Synfuel production displaced some of the conventional coal production in 2001 and 2000. In November 2001, TECO Coal received a private letter ruling from the Internal Revenue Service regarding the production of synthetic fuel from its facilities. The private letter ruling confirms that the facilities produce a qualified fuel eligible for Section 29 tax credits available for the production of such non-conventional fuels through 2007. TECO Coal's net income more than doubled in 2000 to $33.5 million, driven primarily by the sale of fuel produced from the synthetic fuel facilities acquired in early 2000. In 2001, coal sales, including synfuel, increased to 10.1 million tons from 7.9 million tons in 2000 and 7.2 million tons in 1999. In 2002, both coal and synfuel volumes are expected to increase modestly from improved efficiencies and new mines at several facilities. While TECO Coal may sell coal to Tampa Electric on a spot-market basis, it has no contract with Tampa Electric. Metallurgical coal contracts, which normally renew in the first quarter of the year, resulted in improved prices in 2001 and prices are expected to remain strong in 2002. Steam coal pricing improved in the first quarter of 2001, due to better supply and demand balance. TECO Coal contracts much of its steam coal production for the coming year late in the preceding year and
was not able to take full advantage of the higher 2001 prices. However, contract renewals for 2002 were achieved at prices above 2001 levels. In November 2000, TECO Coal purchased Perry County Coal, Inc. Under this purchase, TECO Coal acquired 23 million tons of proven low-sulfur reserves, a preparation plant and two load-out facilities on the CSX railroad. There are an additional 80 million tons of high-quality reserves already under lease located on adjacent land. In January 2000, TECO Coal purchased synfuel facilities from Headwaters Technologies, Inc. which were relocated to the company's Premier Elkhorn and Clintwood Elkhorn mines in Kentucky, and were producing by the second quarter of 2000. These facilities produce synfuel from coal, coal fines and waste coal using a technology licensed from Headwaters. Significant factors that could influence results include weather, general economic conditions, commodity price changes, continued generation of section 29 tax credits which expire after 2007, and changes in laws or regulations. (See the Investment Considerations section.)
________________________________________________________________________________ OTHER UNREGULATED COMPANIES Net income for the other unregulated companies increased 25 percent, driven primarily by higher gas prices at TECO Coalbed Methane and a full year of operation of BCH Mechanical, which was acquired in September 2000. TECO Coalbed Methane's 2001 net income increased as a result of higher gas prices which more than offset naturally declining production. Effective gas prices, net of all hedging, increased 33 percent to $3.66 per thousand cubic feet (Mcf). Production at 15 billion cubic feet (Bcf) declined 4 percent, about half the natural decline rate as a result of well restimulation efforts, in 2001. Proven reserves were estimated at 167 Bcf at Dec. 31, 2001, and 182 Bcf and 159 Bcf in 2000 and 1999, respectively. Net income increased in 2000 as a result of higher gas prices which more than offset lower production. Effective gas prices, net of all hedging, increased to $2.75 per Mcf on production of 15.7 Bcf in 2000. Production in 1999 was 16.6 Bcf. Production is expected to decline 8 percent in 2002, reflective of the normal declining production profile for these types of gas wells. Production from TECO Coalbed Methane's reserves are eligible for Section 29 non-conventional fuels tax credits through 2002. The credit was $1.06 per million Btu in 2000, $1.04 in 1999 and is expected to be $1.06 for 2001. This rate escalates with inflation but could be limited by domestic oil prices. In 2001, domestic oil prices would have had to exceed $48 per barrel for this limitation to have been effective. TECO Coalbed Methane is part of an industry alliance seeking to extend the section 29 tax credits through 2007, coincident with the expiration of other tax credits under this section. In 2001, TECO Coalbed Methane's Section 29 tax credits were $16.1 million. All gas produced is sold under contract at spot market prices. Although natural gas prices can be volatile, the Section 29 tax credits provide stability to TECO Coalbed Methane's operating results. (See the Investment Considerations section.) TECO Solutions was formed to support TECO Energy's strategy of offering customers a comprehensive and competitive package of energy services and products with its Florida operations focus. Operating companies under TECO Solutions include TECO BGA, Inc. (formerly Bosek, Gibson and Associates), BCH Mechanical, Inc. and its affiliated companies (BCH), TECO Gas Services, TECO Properties, Prior Energy Corp., TECO Propane Ventures and TECO Partners. TECO BGA, an energy services company headquartered in Tampa with nine offices throughout Florida and one in California provides design, engineering and construction services to more than 300 customers, including public schools, universities, health care organizations and commercial businesses throughout Florida and California. TECO BGA continues growing its business infrastructure and project portfolio to better compete with the larger energy service companies in the diversified energy service field. Several significant project development efforts are under way. These efforts include providing energy efficiency turnkey services for public and private sector markets, power reliability solutions and district cooling/chilled water plants. In October 2001, TECO BGA acquired a district cooling business from FPL Energy Services. The acquisition included a 12,000-ton design capacity, 3,500- ton installed capacity, cooling plant in Miami and a franchise agreement with the city. The plant serves the American Airlines Arena and a large international Internet/telecommunications center in Miami. The acquisition increases TECO BGA's presence in the Miami market and the plant has potential for increased capacity in the future for additional capital investment. In April 2001, TECO BGA acquired the assets of the energy services division of AMSI Inc., a diversified contracting company located in Ft. Lauderdale, Florida. This acquisition expands TECO BGA's presence in the South Florida market, which accounts for more than 30 percent of the energy services market in Florida. TECO Solutions combines TECO BGA's proven project development and design capabilities with BCH's construction, operations and maintenance capabilities. This combination allows both companies to improve their performance on comprehensive turnkey projects because of in-house skills for the entire project. In November 2001, TECO Solutions acquired Prior Energy Corporation. Prior Energy is a leading natural gas management company in North America, serving customers throughout the Southeast. Prior Energy handles all facets of natural gas energy management services for large commercial, industrial, power generation, municipal and other governmental agency customers, including natural gas acquisition and supply management, transportation management, asset management and consulting services. Prior Energy's activities typically consist of: contracting to purchase specific volumes of gas from producers, pipelines and other suppliers at various points of receipt; aggregating gas supplies and arranging for the transportation of these gas supplies; negotiating to sell specific volumes of gas over a specific period of time to other wholesale marketers and end users; trading gas volumes to optimize storage facilities and other asset management strategies; and providing related risk-management services to its customers. TECO Gas Services, Inc. provides gas management and marketing services similar to Prior Energy for large municipal, industrial, commercial and power generation customers primarily in Florida. This company's focus is on increasing its customer base while continuing to provide gas management services for three large cogeneration facilities. TECO Gas Services is expected to provide gas management services for an increasing customer base as Peoples Gas System makes its "NaturalChoice" option for unbundled service available to more non-residential customers. TECO Propane Ventures (TPV) is the subsidiary in which the company's propane business investment is held. This business was formerly known as Peoples Gas Company, the unregulated propane gas business acquired in the 1997 Peoples Gas companies merger, which was the largest independent propane distributor in Florida. In February 2000, TECO Energy entered into an agreement to form US Propane L.P. to combine its Peoples Gas Company propane operations with the propane operations of Atmos Energy Corporation, AGL Resources, Inc. and Piedmont Natural Gas Company, Inc. In June 2000, US Propane announced that it would combine with Heritage Holdings, Inc., the general partner of Heritage Propane Partners, L.P. (NYSE:HPG), to create the fourth largest retail propane distributor in the United States. Under the agreements, US Propane sold its propane business to Heritage Propane for approximately $180 million in cash and limited partnership units of Heritage Propane Partners.
US Propane purchased all of the ownership interest of Heritage Holdings, the general partner of Heritage Propane Partners, for $120 million. Upon closing of the transaction, US Propane owned all of the general partner and an approximate 34 percent limited partnership interest in Heritage Propane Partners, the master limited partnership. Interests in the general partner of US Propane are held proportionately among the four companies that created US Propane. TPV recorded an $8.3-million after-tax gain from this series of transactions in 2000. TPV has a 38 percent interest in the general partner that manages Heritage Propane Partners. After Heritage Propane Partners issued new equity to the public in 2001, US Propane continued to own all of the general partner and were diluted down to an approximate 29 percent limited partnership interest of Heritage Propane Partners.
________________________________________________________________________________ NON-OPERATING ITEMS
Non-Operating Items Impacting Net Income
2001 Items In 2001, TECO Energy's results included charges to adjust asset valuations totaling $7.2 million after tax. The adjustments included a $6.1-million after- tax adjustment related to the sale of TECO Power Services' (TPS) minority interests in Energia Global International, Ltd. which owns smaller power generation projects in Central America, and a $1.1-million after-tax charge related to the sale of leveraged leases at TECO Investments.
2000 Items In 2000, TECO Energy's results included an $8.3-million after-tax gain from the US Propane and Heritage Propane transactions offset by after-tax charges of $5.2 million to adjust the value of leveraged leases and $3.8 million to adjust property values at TECO Properties.
1999 Items Unusual and non-recurring charges in 1999 totaled $21.1 million pretax ($19.6 million after tax) and consisted of the following: Tampa Electric recorded a charge of $10.5 million ($6.4 million after tax) based on Florida Public Service Commission audits of its 1997 and 1998 earnings which, among other things, limited its regulatory equity ratio to 58.7 percent, a decrease of 91 basis points and 224 basis points from 1997's and 1998's ratios, respectively. Tampa Electric also recorded an after-tax charge of $3.5 million, representing management's estimate of additional expenses to resolve litigation filed by the United States Environmental Protection Agency (EPA). (See the Environmental Compliance section.) After-tax charges totaling $6.1 million were also recorded reflecting corporate income tax provisions and settlements related to prior years' tax returns. These charges were recorded at Tampa Electric (a $3.8-million net after-tax charge after recovery under the regulatory agreement then in effect) and at TECO Energy (a $2.3-million after-tax charge). A charge of $6.0 million ($3.6 million after tax) was recorded to adjust the carrying value of certain investments in leveraged aircraft leases to reflect lower anticipated residual values.
Discontinued Operations In November 1999, the assets of TeCom, the company's advanced energy management technology subsidiary, were sold. In connection with the exit of this business, an after-tax charge of $12.9 million was recorded in 1999, representing the write-off of all capitalized development costs, severance and other exit costs partially offset by sale proceeds.
Other Income (Expense) Other income (expense) in 2001 included income recognized on equity investments in generation projects and EEGSA at TPS and income from the investment in TPV, offset by a $9.9 million pretax charge ($6.1 million after- tax) for TPS' sale of its minority interest in EGI. Other income (expense) in 2000 included a pretax gain of $13.6 million associated with the US Propane and Heritage Propane transactions, $5.4 million from an insurance settlement at TPS, and interest income from the TPS investments made in the form of loans. Also included in 2000 was a charge of $8.1 million to adjust the value of certain leveraged lease investments. Other income (expense) in 1999 included charges of $3.5 million to provide for Tampa Electric's expected costs of settling an EPA lawsuit, $10.5 million for a regulatory decision limiting the utility's regulatory equity ratio to 58.7 percent for 1997 and 1998, and $6.0 million to adjust the carrying value of certain leveraged lease investments. AFUDC was $6.6 million in 2001, $1.6 million in 2000 and $1.3 million in 1999. AFUDC is expected to increase to an estimated $20 million in 2002 and remain at that level in 2003, primarily reflecting Tampa Electric's growing investment in the Gannon to Bayside repowering.
Interest Charges Interest charges at TECO Energy were $166.4 million in 2001 compared to $167.6 million in 2000 and $123.7 million in 1999. The slight decline in 2001 was primarily because of lower short-term debt rates. The increase in 2000 was primarily because of higher borrowing levels associated with the company's business development activities and higher short-term interest rates.
Income Taxes Income tax expense decreased in 2001, reflecting higher taxable income offset by a substantial increase in tax credits associated with the production of non- conventional fuels. In 2000, income tax expense decreased from the prior year reflecting lower taxable income and the effect of increased tax credits over 1999. Income tax expense as a percentage of income from continuing operations before taxes was -3 percent in 2001, 7 percent in 2000 and 30 percent in 1999. The cash payment for income taxes, as required by the Alternative Minimum Tax Rules, was $52.4 million, $83.9 million and $62.1 million in 2001, 2000 and 1999, respectively. Total income tax expense was reduced by the Federal tax credit related to the production of non-conventional fuels, under Section 29 of the Internal Revenue Code. This tax credit totaled $102.3 million in 2001, $68.3 million in 2000 and $17.2 million in 1999. These tax credits are generated annually on qualified production at TECO Coalbed Methane through December 31, 2002 and at TECO Coal through December 31, 2007, subject to changes in law, regulation or administration that could impact the qualification of Section 29 tax credits. The tax credit is determined annually and was $1.04 per million Btu in 1999, $1.06 per million Btu in 2000 and is expected to be $1.06 for 2001. This rate escalates with inflation but could be limited by domestic oil prices. In 2001, domestic oil prices would have had to exceed $48 per barrel for this limitation to have been effective. In 2001 and 2000, the decreased income tax expense also reflected the impact of increased overseas operations with deferred U.S. tax structures. The decrease related to these deferrals was $7.2 million, $9.3 million and $1.4 million for 2001, 2000, and 1999, respectively. The income tax effect of gains and losses from discontinued operations is shown as a component of results from discontinued operations. Income tax expense for 1999 included $5.0 million for charges described above in 1999 items, reflecting corporate income tax provisions and settlement expenses related to prior years' tax returns. These adjustments, including interest of $9.0 million, were recorded at Tampa Electric, TECO Investments and at the TECO Energy corporate level.
- -------------------------------------------------------------------------------- ACCOUNTING STANDARDS
Accounting for Derivative Instruments and Hedging Effective Jan. 1, 2001, the company adopted Financial Accounting Standard (FAS) 133, Accounting for Derivative Instruments and Hedging. The new standard requires the company to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value, and to reflect the changes in fair value of those instruments as either components of comprehensive income or in net income, depending on the types of those instruments. At adoption, the company had derivatives in place at TECO Coalbed Methane that qualified for cash flow hedge accounting treatment under FAS 133, and recorded an opening swap liability of $19.0 million and an after-tax reduction to other comprehensive income of $12.6 million. At the time derivative contracts are entered into, the company determines whether the derivative is subject to the requirements of FAS 133 or meets criteria for exclusion such as for certain normal purchases and sales activity. All contracts requiring FAS 133 accounting are designated as a cash flow hedge, fair value hedge or as a trading instrument, and formal documentation of relationships between hedging instruments and the hedged items, hedging objective and strategy, and methods for assessing hedge effectiveness both at the hedge's inception and on an ongoing basis is completed. From time to time, TECO Energy enters into futures, swaps and options contracts to hedge the future selling price for its physical production at TECO Coalbed Methane, to limit exposure to gas price fluctuations for future purchases at Peoples Gas System and at Prior Energy, to limit exposure to interest rate fluctuations at TECO Energy and other affiliates, to limit exposure to electricity and other commodity fluctuations at TECO Power Services, and to limit exposure to fuel price increases on future purchases at TECO Transport. As such, most of the company's derivative activity that cannot be excluded from the requirements of FAS 133 receives cash flow hedge accounting treatment. Cash Flow Hedges: For the year ended Dec. 31, 2001, the company recognized a loss of $19.7 million for the cash flow hedges that were settled. Of this amount, $6.5 million was reported as a reduction to revenue related to hedges of future sales at TECO Coalbed Methane, and $13.2 million was reported as operating expenses related to hedges of future gas purchases at Peoples Gas and Prior Energy. As of Dec. 31, 2001, the company had open hedging transactions that qualify for cash flow hedge accounting treatment at Prior Energy, TECO Coalbed Methane, Peoples Gas and TECO Transport with a net pretax liability fair value of $29.5 million. Of this total, $28.2 million is expected to be reclassified to earnings within the next twelve months on instruments with maturity dates throughout 2002 when the related future transactions take place. Unrealized after tax losses on all open cash flow hedges of $8.1 million were recorded as a reduction to other comprehensive income, with an additional $17.4 million representing open cash flow hedges prior to the Nov. 1, 2001 acquisition of Prior Energy, were recorded as a deferred charge. The company, through its TECO Power Services subsidiary, has an equity investment in a partnership with Panda Energy. The partnership utilizes interest rate swap agreements to effectively convert a portion of its floating rate debt to a fixed rate basis, thereby reducing the impact of interest rate changes on construction costs and future income. On the interest rate swap agreements, the partnership pays a fixed rate and receives a variable rate based on London Interbank Offered Rates (LIBOR), with terms ranging from 2 to 5 years. At Dec. 31, 2001 the company recorded $11.2 million for its equity portion of the unrealized losses on these cash flow hedge swaps reflecting the sharp decline in floating interest rates since the inception of the swap agreements as a reduction to other comprehensive income and a corresponding reduction to the investment account. Fair Value Hedges: For the year ended Dec. 31, 2001, the company recognized losses of $0.1 million as operating expenses for changes in the fair value of derivatives classified as fair value hedges. As of Dec. 31, 2001, the company had open hedging transactions against gas storage inventory at Prior Energy that qualify for fair value hedge accounting treatment with a net derivative asset pretax value of $0.9 million, all of which is expected to be reclassified to earnings within the next twelve months. Trading Derivatives: The company has entered into a limited number of financial derivatives at its TECO Power Services and Prior Energy affiliates which do not qualify for hedge accounting treatment under FAS 133. TECO Power Services has a capacity call option, which is marked-to-market. The fair value of these options is determined using an industry standard model from the Financial Engineering Association which is based on the Black-Scholes valuation model and evaluates current prices, volatility of prices and time to expiration of the options. For the year ended Dec. 31, 2001, the company recognized a pretax loss of $0.8 million for the decrease in fair value on these options. As of Dec. 31, 2001, the $1.5 million fair value of these options is included in current assets, all of which is expected to be realized within the next twelve months. As of Dec. 31, 2001, Prior Energy had several open swap and option positions where they acted as the counterparty to the transactions. These contracts are marked-to-market under FASB's Emerging Issues Task Force (EITF) release Issue 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The fair value for these derivatives is determined using the Henry Hub Natural Gas futures prices as actively quoted on the New York Mercantile Exchange (NYMEX). For the year ended Dec. 31, 2001, the company recognized $0.7 million in pretax losses related to these derivatives. As of Dec. 31, 2001, $7.5 million of pretax fair value of open liability positions is offset by $7.4 million of open asset positions, all of which is expected to be realized within the next twelve months. The following tables summarize the changes in and the fair value balances of trading derivative assets (liabilities) for the year ended Dec. 31, 2001.
Business Combinations, Goodwill and Other Intangible Assets On June 30, 2001, the Financial Accounting Standards Board finalized FAS 141, Business Combinations, and FAS 142, Goodwill and Other Intangible Assets. FAS 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method of accounting. With the adoption of FAS 142 effective Jan. 1, 2002, goodwill is no longer subject to amortization. Rather, goodwill will be subject to at least an annual assessment for impairment by applying a fair-value-based test. Under the new rules, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through con-
tractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented, or exchanged, regardless of the acquirer's intent to do so. These intangible assets will be required to be amortized over their useful lives. As of Dec. 31, 2001, TECO Energy had $166 million of goodwill, net of accumulated amortization of $10 million. Adoption of FAS 142 effective Jan. 1, 2002 will result in the elimination of approximately $5 million of annual amortization, subject to the identification of separately recognized intangibles which would continue to be amortized under the new rules. TECO Energy is beginning the initial impairment testing of all goodwill, and does not anticipate an initial impairment charge upon adoption of FAS 142.
Accounting for Asset Retirement Obligations In July 2001, the Financial Accounting Standards Board finalized FAS 143, Accounting for Asset Retirement Obligations, which requires the recognition of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is adjusted to its present value and the related capitalized charge is depreciated over the useful life of the asset. FAS 143 is effective for fiscal years beginning after June 15, 2002. The company is currently reviewing the impact that FAS 143 will have on its results.
Accounting for the Impairment or Disposal of Long-Lived Assets In August 2001, the Financial Accounting Standards Board issued FAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets. FAS 144 addresses accounting and reporting for the impairment or disposal of long-lived assets, including the disposal of a segment of a business, and supersedes FAS 121, Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of. FAS 144 is effective for fiscal years beginning after December 15, 2001. The company periodically assesses whether there has been a permanent impairment of its long-lived assets and certain intangibles held and used by the company in accordance with FAS 121, and beginning in 2002 with FAS 144. The company does not anticipate that the adoption of FAS 144 will have a significant impact on its financial statements.
- -------------------------------------------------------------------------------- ENRON EXPOSURE On Dec. 2, 2001, Enron Corp., a large energy trading and services company, filed for protection under the U.S. Bankruptcy Code. TECO Energy believes that its exposure in operations from trade payables and other trading positions due to the Enron bankruptcy totals $3.5 million or less after tax at its subsidiaries, TPS, PGS and Prior Energy, its new gas marketing subsidiary. An Enron subsidiary, NEPCO, is currently serving as the construction contractor for four merchant power stations in which TPS has interests. Enron guaranteed certain of NEPCO's obligations under the construction contracts. Two of the projects for which NEPCO is the contractor, the Union and Gila River power stations, which are sponsored by a joint venture of TPS and Panda Energy, have financing in place with a syndicate of banks. The other two projects, the Dell and McAdams power stations, are 100 percent owned by TPS and were in the process of being financed at the time of the Enron bankruptcy. As part of Enron's centralized cash management procedure, NEPCO's cash was swept by Enron before being applied to pay project costs. As a result of these cash sweeps, net of NEPCO profit and contingency amounts, there appears to be a potential aggregate capital cost overrun for the four projects of approximately $80 million, of which, as described below, $63 million relates to the Union and Gila River projects. To date, NEPCO has continued construction and engineering work on these power plants and the construction of all four plants is on schedule. TPS and Panda have reached a series of agreements with NEPCO for the projects. These agreements are designed to permit the construction of the four plants to continue on schedule and within the estimated total construction cost amounts including project contingencies. These revisions allow TPS to make direct payments to subcontractors and suppliers, and provide for no profit or markup to NEPCO. Enron's bankruptcy permitted the project lenders to stop funding construction costs for the Union and Gila River projects until the condition was cured or waived. TPS received approval from the project lenders on a plan that allowed funding to resume. The plan involves TECO Energy replacing Enron as the guarantor of certain of NEPCO's obligations under the construction contracts for these two projects, including payment by the company of any project cost overruns (currently estimated at $63 million, against which TECO Energy could offset any of the unused construction contingency amount remaining after completion of construction). The plan also provided for TECO Energy to replace the letter of credit furnished by Enron that had been drawn upon and acceleration of $200 million of project cash commitments to mid-year 2002, with the result that TECO's total investment of $1.1 billion is expected by October 2002 rather than mid-2003 as originally planned. Although TECO Energy is not directly obligated by the project financing, it has commitments to the lenders to make additional cash contributions to the projects of $493 million in addition to the $624 million, including the $500 million equity bridge loan, it has already made. NEPCO has not filed for bankruptcy, but has told TPS that it may do so in order to accomplish a sale of substantially all of its assests, pursuant to Section 363 of the Bankruptcy Code. In the event of such a sale, TPS expects that it would enter into new contracts with the purchaser of such assets effective upon approval of the sale by the bankruptcy court. If NEPCO had to be replaced as contractor (as a result of a sale of its assets or otherwise), it is possible that there would be delays in the project schedules and additional project costs. A new contractor would also have to be reasonably satisfactory to the project lenders for the Union and Gila River projects. Financing activities for the other two projects, the Dell and McAdams power stations, resumed shortly after the bank approval was received for the resumption of funding for the Union and Gila River power stations. Financing for these plants is expected to be completed in 2002.
- -------------------------------------------------------------------------------- ENVIRONMENTAL COMPLIANCE Tampa Electric Company is a party to a consent decree with the EPA and a consent final judgement with the U.S. Department of Justice, effective Oct. 5, 2000, and the Florida Department of Environmental Protection (FDEP) effective December 7, 1999. Pursuant to these consent decrees, allegations of violations of New Source Review requirements of the Clear Air Act were resolved, provision was made for environmental controls and pollution reductions, and Tampa Electric is committed to a comprehensive program that will dramatically decrease emissions from the company's power plants. The emission reduction plan included specific detail with respect to the availability of the scrubbers and earlier incremental NOx reduction efforts on Big Bend Units 1, 2 and 3 and the repowering of the company's coal-fired Gannon Station to fire natural gas. Engineering for the repowering project began in January 2000, and Tampa Electric anticipates that commercial operation for the first repowered unit is expected by May 1, 2003. The repowering of the second unit is scheduled for completion by May 1, 2004. When these units are repowered, the station will be renamed the Bayside Power Station and will have total station capacity of about 1,800 megawatts (nominal) of natural gas-fueled electric generation. In November 2000, the FPSC approved recovery through the Environmental Cost Recovery Clause of costs incurred to improve the availability and removal efficiency for its Big Bend 1, 2 and 3 scrubbers, to reduce particulate matter emissions, and to reduce NOx emissions. The approved cost recovery for these various environmental projects through customers' bills started in January 2001. Tampa Electric Company is a potentially responsible party for certain superfund sites and,
through its Peoples Gas System division, for certain superfund and 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 $22 million over the next 10 years. The expected environmental remediation costs associated with these sites are not expected to have a significant impact on customer prices.
- -------------------------------------------------------------------------------- UTILITY REGULATION
Rate Stabilization Strategy Tampa Electric's objectives of stabilizing prices from 1996 through 1999 and securing fair earnings opportunities during this period were accomplished through a series of agreements entered into in 1996 with Florida's Office of Public Counsel (OPC) and the Florida Industrial Power Users Group (FIPUG) which were approved by the Florida Public Service Commission (FPSC). Prior to these agreements, the FPSC approved a plan submitted by Tampa Electric to defer certain 1995 revenues. In general, under these agreements Tampa Electric was allowed to defer revenues in 1995 and 1996 during the construction of Polk Unit 1 and recognize these revenues in 1997 and 1998 after commercial operation of the unit. Other components of the agreements were a base rate freeze through 1999 and refunds to customers totaling $50 million during the period October 1996 through December 1998 while Tampa Electric was allowed recovery of the capital costs incurred for the Polk Unit 1 project. As part of its series of agreements with OPC and FIPUG, Tampa Electric agreed to refund 60 percent of 1999 revenues that contributed to an ROE in excess of 12 percent, as calculated and approved by the FPSC. In October 2000, the FPSC staff recommended a 1999 refund of $6.1 million including interest, to be refunded to customers beginning January 2001. OPC objected to certain interest expenses recognized in 1999 that were associated with prior tax positions and used to calculate the amount to be refunded. Following a review by the FPSC staff, the FPSC agreed in December 2000 that the original $6.1 million was to be refunded to customers. In February 2001, OPC protested the FPSC's decision. The protest claimed that the stipulations did not allow for the inclusion of the interest expenses on income tax positions in the refund calculations. The FPSC held hearings on the issue in August 2001 and upheld its decision that the original refund amount plus interest was appropriate under the agreements. In January 2002, the OPC filed a motion with the FPSC asking for reconsideration of its decision, alleging the FPSC relied on erroneous information. Tampa Electric will begin making refunds to customers when the decision can no longer be appealed. The regulatory arrangements described above covered periods that ended on Dec. 31, 1999. Tampa Electric's rates and its allowed ROE range of 10.75 percent to 12.75 percent with a midpoint of 11.75 percent will continue in effect until such time as changes are occasioned by an agreement approved by the FPSC or other FPSC actions as a result of rate or other proceedings initiated by Tampa Electric, FPSC staff or other interested parties. Tampa Electric expects to continue earning within its allowed ROE range.
Cost Recovery Clauses In February 2001, Tampa Electric notified the FPSC that it anticipated that the fuel factors approved in December 2000 for 2001 were understated by approximately $86 million due to significantly higher natural gas and oil prices and, accordingly, purchased power costs. In March 2001, the FPSC approved Tampa Electric's request to increase rates to cover the $86 million beginning in April 2001 and ending in December 2002. In September 2001, Tampa Electric filed with the FPSC for approval of fuel and purchased power, capacity, environmental and conservation cost recovery clause rates for the period January 2002 through December 2002. In November, the FPSC approved Tampa Electric's requested changes. Accordingly, Tampa Electric's residential customer rate per 1,000-kilowatt hours increased by $6.18 to $93.94. These rates include projected costs associated with environmental projects required under the U.S. EPA Consent Decree and the FDEP Consent Final Judgment with Tampa Electric. They also include higher coal prices expected for 2002 and additional purchased power costs for 2001 and 2002, which reflect higher natural gas and oil prices and increases in the volumes of purchased power. In January 2001, PGS notified the FPSC that it anticipated that its purchased gas adjustment factors approved in December 2000 for 2001 were understated by approximately $63 million due to significantly higher natural gas prices. In February 2001, the FPSC approved PGS' request to increase rates to cover the $63 million under-recovery beginning in March 2001. In April, and again in June, PGS lowered the purchased gas adjustment factor as gas prices declined from their winter time highs.
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 alternatives through various initiatives, including legislative and/or regulatory changes that would permit competition at the retail level. Tampa Electric intends to retain and expand its retail business by managing costs and providing high-quality service to retail customers. 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. However, the Florida Power Plant Siting Act, which sets the state's electric energy/environmental policy and governs the building of new generation involving steam capacity of 75 megawatts or more, requires that applicants demonstrate that a plant is needed prior to receiving construction and operating permits. In 2000, Florida Governor Jeb Bush established the 2020 Energy Study Commission to address the following issues by December 2001: current and future reliability of electric and natural gas supply; emerging energy supply and delivery options; electric industry competition; environmental impacts of energy supply; energy conservation and fiscal impacts of energy supply options on taxpayers and energy providers. TECO Energy has been supportive of the process. The Study Commission submitted its final recommendation to Governor Bush in December 2001 which included, among other things, elimination of barriers to entry for merchant power generators, an open competitive wholesale electric market, transfer of regulated generating assets to unregulated affiliates or sale to others, Florida electric system reliability and consumer protection. A proposal is expected to be forwarded to the legislature by the Governor for possible action as early as the 2002 legislative session. It is unclear at this time if this proposed legislation would pass.
Regional Transmission Organization (RTO) In December 1999, the Federal Energy Regulatory Commission (FERC) issued Order No. 2000, dealing with RTOs. This rule is driven by the FERC's continuing effort to effect open access to transmission facilities in large, regional markets. The rule provides guidelines to utilities for joining RTOs by December 2001. These guidelines specify minimum characteristics and functions. In anticipation of the FERC activity, the FPSC held workshops in 1999 to discuss transmission issues within peninsular Florida. Potentially affected parties and the FPSC agreed that a national one-size-fits-all approach is not appropriate. With the encouragement of the FPSC, Tampa Electric worked with utilities in the state and others to develop a peninsular Florida solution.
The activities resulted in the peninsular Florida investor-owned utilities making joint RTO filings at FERC in October and December 2000. In the filing, Tampa Electric agreed with the other Florida investor-owned utilities to form an RTO to be known as GridFlorida LLC. GridFlorida would independently control the transmission assets of the filing utilities, as well as other utilities in the region that choose to join. The RTO would be an independent, investor-owned organization that would have control of the planning and operations of the bulk power transmission systems of the utilities within peninsular Florida. In addition, GridFlorida was proposed to be a transmission company (or transco) that would own transmission assets. Tampa Electric planned to contribute its transmission assets to GridFlorida in exchange for a passive interest. The three filing utilities represent almost 80 percent of the aggregate net energy load in the region for the year 2000. In March 2001 FERC conditionally approved GridFlorida, which led to a May 2001 compliance filing by the three filing utilities at FERC addressing the changes FERC required in their approval before GridFlorida could move ahead. FERC has not yet acted on this latest filing. In May 2001, the FPSC questioned the prudence of the three filing utilities joining GridFlorida as conditionally approved by FERC. Upon the request of the three utilities, the FPSC granted the opening of an accelerated docket regarding the prudence of GridFlorida. Hearings were held in October 2001, and the FPSC ruled that, while the companies were prudent in forming GridFlorida, the FPSC was not satisfied with the transmission-owning features of the GridFlorida filing nor with the proposal that any of the filing utilities transfer ownership of their assets to GridFlorida. Accordingly, the FPSC ordered the companies to develop a new RTO model which was filed at the FPSC in late March 2002 that addresses its concerns. Tampa Electric plans to take an active role in monitoring and influencing the development of possible RTOs in the southeast region.
Utility Competition: Gas Although Peoples Gas System is not in direct competition with any other regulated distributors of natural gas for customers within its service areas, there are other forms of competition. At the present time, the principal form of competition for residential and small commercial customers is from companies providing other sources of energy, including electricity. In November 2000, PGS implemented its "NaturalChoice" program that offers unbundled transportation service to all non-residential customers. This means that non-residential customers can purchase commodity gas from a third party but continue to pay PGS for the transportation of the gas. 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, by transporting gas through other facilities, thereby bypassing PGS facilities. In response to this competition, various programs have been developed including the provision of transportation services at discounted rates. In general, PGS faces competition from other energy source suppliers offering fuel oil, electricity and in some cases, propane. PGS has taken actions to retain and expand its commodity and transportation business, including managing costs and providing high-quality service to customers. In March 2000, the franchise agreement between the city of Lakeland (City) and PGS expired. The City has initiated legal proceedings seeking a declaration of the City's rights to acquire the PGS facilities under the franchise. PGS has filed defenses and counterclaims and after a series of hearings the core issues of the case relating to the City's rights to purchase the system have still not been heard. Due to further motions and the potential for appeals, resolution through the courts is not expected for many months. While PGS believes it is best suited to serve these customers, it cannot at this time predict the ultimate outcome of these activities. PGS is continuing to serve under substantially the same terms as contained in the franchise agreement in the absence of other rules and regulations being, adopted by the City. The Lakeland franchise contributed about $4.5 million of net revenue to PGS results in 2001.
- -------------------------------------------------------------------------------- CAPITAL INVESTMENTS
- -------------------------------------------------------------------------------- Actual Forecast ---------------------------------------------- $ (millions) 2001 2002 2003 2004 - 2006 2002 - 2006 Total - -------------------------------------------------------------------------------- Florida Operations $ 533 $ 603 $ 359 $ 761 $ 1,723 Independent Power 554 514 352 -- 866 Transportation (4) 20 24 55 99 Other 23 46 29 46 121 - -------------------------------------------------------------------------------- Total $1,106 $1,183 $ 764 $ 862 $ 2,809 - --------------------------------------------------------------------------------
TECO Energy's 2001 capital investment of $1,106 million included $426 million for Tampa Electric (including AFUDC), $73 million for Peoples Gas System and $573 million for the unregulated companies. Tampa Electric's capital investments in 2001 were $225 million for equipment and facilities to meet its growing customer base and generating equipment maintenance, $183 million for the repowering and conversion of the coal-fired Gannon Station to the natural gas-fired Bayside Station (see the Environmental Compliance section) and $18 million for the construction of Polk Unit 3 which is a natural gas and No. 2 oil-fired combustion turbine. Capital expenditures for Peoples Gas System were approximately $54 million for system expansion and approximately $19 million for maintenance of the existing system. TECO Transport invested $39 million in 2001 for equipment additions and normal equipment replacement, offset by $43 million in proceeds from a sale/lease back transaction at TECO Ocean Shipping. (See Financing Activity section). TECO Coal spent $26 million, which includes $9 million for the expansion of production at Perry County and Clintwood, and the balance for normal equipment replacements. TECO Power Services' capital investments totaled $784 million related to the Commonwealth Chesapeake Power Station, the Union, Gila River, Dell and McAdams power stations and the purchase of the Frontera Power Station. The $554 million, shown for independent power in the table above, is net of $197 million of non-recourse financing and is net of the proceeds from the sale of EGI received in 2001. TECO Energy estimates net capital investments for ongoing operations to be $1.2 billion for 2002, $800 million for 2003 and $900 million during the 2004-2006 period. For 2002, Tampa Electric expects to spend $541 million, consisting of $330 million for the repowering project at the Gannon Station, $16 million in construction costs on Polk Unit 3 and $195 million to support system growth and generation reliability. At the end of 2001, Tampa Electric had outstanding commitments of about $453 million for the Gannon Station repowering project and Polk Unit 3. Tampa Electric's total capital expenditures over the 2003-2006 period are projected to be $878 million, including $131 million for the repowering project. Capital expenditures for Peoples Gas System are expected to be about $62 million in 2002 and $242 million during the 2003-2006 period. Included in these amounts are approximately $42 million annually for projects associated with customer growth and system expansion. The remainder represents capital expenditures for ongoing maintenance and system safety. TECO Power Services expects to invest $514 million in 2002, net of $500 million of non-recourse project financing expected for the Dell, McAdams, Frontera and Commonwealth Chesapeake power stations, and $320 million in 2003 for the completion of the Gila River, Union, Dell and McAdams power stations. Estimates for TPS include net contributions to projects of unconsolidated affiliates and other investments of $984 million. These amounts, consisting of equity investments in the Union and Gila River Power Stations, are estimated at $664 million in 2002 and $320 million in 2003. The 2002 amounts are net of $460 million of non-recourse project construction for the Union and Gila River power stations, (see Financing Activity section) and include $125 million of TPS equity investment upon completion of the first phase of the Union Power Station. Capital investment estimates reflect committed projects and do not take into account future opportunities that may emerge.
TPS had contractual commitments of $1.1 billion at the end of 2001, primarily for the construction of the Union, Gila River, Dell and McAdams power stations and are reflected in the capital investments table above. The other unregulated companies expect to invest $66 million in 2002 and $154 million during the 2003-2006 period. Included in these amounts is normal renewal and replacement capital including coal mining equipment. See the Liquidity, Capital Resources section for a description of TECO Energy's plans to finance these capital investments.
- -------------------------------------------------------------------------------- INVESTMENT ACTIVITY At Dec. 31, 2001, TECO Energy had $120.2 million in cash, cash equivalents and short-term investments, compared to $99.6 million at year-end 2000. Year-end cash balances were higher than normal in both years. At the end of 2001, cash balances included the proceeds from a sale-leaseback transaction at TECO Transport, which were applied to short-term debt balances in early 2002. At the end of 2000, cash balances included the proceeds from a TPS lease transaction, which were applied to short-term debt balances in early 2001. (See Financing Activity section.) Other investments of $303 million included notes receivable from unconsolidated affiliates and investments in leveraged leases; $93 million of the notes receivable mature within one year. Other Investments decreased $103 million in 2001, reflecting repayments from the proceeds of the TPS/Panda Energy project financing of amounts advanced by TECO Energy to the projects. The balance is expected to decrease during the fourth quarter of 2002 as these notes mature. Investments in unconsolidated affiliates of $172.9 million at Dec. 31, 2001 decreased from $195.9 million at Dec. 31, 2000. The balances at Dec. 31, 2001 include TPS's ownership interest in EEGSA, TECO Propane Ventures' 38-percent interest in US Propane and TECO Properties interests in real estate projects. Activity in 2001 was largely associated with TPS' sale of its minority interest in EGI. The continuing investment in leveraged leases was $15.6 million at Dec. 31, 2001, down from $22 million last year, reflecting the sale of commuter aircraft leases in 2001.
- -------------------------------------------------------------------------------- FINANCING ACTIVITY TECO Energy's 2001 year-end capital structure, excluding the effect of unearned compensation, was 59.6 percent debt, 3.6 percent trust preferred securities and 36.8 percent common equity. TECO Power Services typically finances its power projects with non-recourse project debt. Excluding this non-recourse debt of $238.4 million, the year-end capital structure was 57.8 percent debt, 3.8 percent trust preferred securities and 38.4 percent common equity. Taking into account the January 2002 issuance of mandatorily convertible equity units, TECO Energy's 2001 year-end capital structure, on a pro forma basis, excluding the effect of unearned compensation, was 51.6 percent debt, 11.6 percent trust preferred and mandatorily convertible equity units and 36.8 percent common equity. Excluding this non-recourse project debt of $238.4 million, the year-end capital structure was 49.5 percent debt, 12.1 percent trust preferred and mandatorily convertible equity units and 38.4 percent common equity.
- -------------------------------------------------------------------------------- CREDIT RATINGS/SENIOR UNSECURED DEBT - -------------------------------------------------------------------------------- Fitch Moody's Standard & Poor's - -------------------------------------------------------------------------------- Tampa Electric A+ A1 A TECO Finance / TECO Energy A- A3 A- - --------------------------------------------------------------------------------
In 2000 and 2001, Moody's Investor Services, Inc., Standard & Poor's Ratings Service and Fitch Investor Services, Inc. lowered the ratings on the debt securities of TECO Energy and Tampa Electric. The outlook assigned by each agency is negative. The ratings actions were attributed to increased debt levels and the changing risk profile associated with the expansion of TECO Energy's independent power development activities, as well as the required capital outlays of Tampa Electric, the uncertainties related to industry restructuring and the additional risks and obligations undertaken by TECO Energy with respect to various TPS projects. These downgrades and any further downgrades, may affect the company's ability to borrow and increase its financing cost which may decrease earnings. Execution of the company's business strategy will increase the proportion of unregulated power generation in TECO Energy's business mix. The company continues to evaluate the financial policies required for this more competitive business environment in order to maintain appropriate credit ratings for both Tampa Electric and TECO Energy. The objective for both TECO Energy and Tampa Electric is to maintain strong investment-grade credit ratings that provide the companies with continued access to the commercial paper markets.
Financing activity by company
TECO Energy: In January 2002, TECO Energy sold 17.965 million units of mandatorily convertible equity units in the form of 9.5% equity units at $25 per unit resulting in $436 million of net proceeds. Each equity unit consisted of $25 in principal amount of a trust preferred security of TECO Capital Trust II, a Delaware business trust formed by TECO Energy, with a stated liquidation amount of $25 and a contract to purchase shares of common stock of TECO Energy in January 2005 at a price per share of between $26.29 and $30.10 based on the market price at that time. The equity units represent an indirect interest in a corresponding amount of TECO Energy subordinated debt. The net proceeds from the offering were used to repay short-term debt and for general corporate purposes. In March 2001, the company completed a public offering of 8.625 million common shares, resulting in net proceeds to the company of approximately $232 million. In October 2001, Standard & Poor's (S&P) announced the inclusion of TECO Energy shares in the S&P 500 index effective as of the market close on Oct. 9, 2001. On Oct. 12, 2001, the company issued 3.5 million additional common shares as a result of the increased demand for its shares on its inclusion in the S&P 500 index. The net proceeds were $26.72 per share or approximately $93 million. The proceeds from the sale of these common shares were used to repay short-term debt and for general corporate purposes. In May 2001, the company issued $400 million principal amount of 7.20% notes due May 1, 2011. These notes are redeemable at the option of the company, in whole or in part, from time to time, at a redemption price equal to the greater of 100% of the principal amount of the notes then outstanding to be redeemed or the sum of the present value of the remaining scheduled payments of principal and interest on the notes then outstanding to be redeemed, discounted at an adjusted treasury rate plus 25 basis points to the redemption date. Net proceeds of $396 million were used to repay short-term debt and for general corporate purposes. In September 2001, the company issued an additional $200 million principal amount of this note series. Net proceeds of $206 million were used to effect a debt for debt exchange of $150 million of bonds issued in 1998, and to repay short-term debt and for general corporate purposes. In May 2001, the company sold $400 million principal amount of one-year, floating rate notes in a private placement. The notes were issued at an initial rate of 5.203%, and are callable at par on Nov. 15, 2001, and monthly thereafter. Rates on these securities are reset quarterly at a spread of 110 basis points over three-month LIBOR. Net proceeds of $399 million were used to repay short-term debt and for general corporate purposes. In December 2000, TECO Energy issued $200 million of retail trust preferred securities (TRuPS). These securities were issued at a $25 per share par value and an 8.5% coupon with distribution payable quarterly. These securities have a January 31, 2041 maturity date but are
callable at par after Dec. 20, 2005. These securities represent an indirect interest in a corresponding amount of TECO Energy subordinated debt. In September 2000, TECO Energy issued $200 million of remarketed notes, due 2015. The notes, which bear an initial coupon rate of 7.0%, are subject to mandatory tender on Oct. 1, 2002, at which time they will be remarketed or redeemed. Net proceeds were $206.3 million, which included a premium paid to TECO Energy by the remarketing agent for the right to purchase and remarket the notes in 2002. If this right is exercised, for the following 10 years the notes will bear interest at 5.86% plus a premium based on TECO Energy's then-current credit spread above United States Treasury Notes with 10 years to maturity.
Tampa Electric: In June 2001, Tampa Electric issued $250 million principal amount of 6.875% notes due on June 15, 2012. The notes are redeemable at the option of Tampa Electric, in whole or in part, from time to time, at a redemption price equal to the greater of 100% of the principal amount of the notes then outstanding to be redeemed or the sum of the present value of the remaining scheduled payments of principal and interest on the notes then outstanding to be redeemed, discounted at an adjusted treasury rate plus 25 basis points to the redemption date. Net proceeds of $248.9 million were used to repay short-term debt and for general corporate purposes. In August 2000, Tampa Electric issued $150 million of remarketed notes, due 2015. The notes, which bear an initial coupon rate of 7.37% are subject to mandatory tender on Sept. 1, 2002, at which time they will be remarketed or redeemed. Net proceeds were $154.2 million, which included a premium paid to Tampa Electric by the remarketing agent for the right to purchase and remarket the notes in 2002. If this right is exercised, for the following 10 years the notes will bear interest at 5.75% plus a premium based on Tampa Electric's then-current credit spread above United States Treasury Notes with 10 years to maturity.
TECO Transport: In April 2001, TECO Bulk Terminal, a wholly-owned subsidiary of TECO Transport, converted $110.6 million of tax-exempt debt related to its docks and wharves from commercial paper mode to a fixed rate mode with a coupon rate of 5.0%. These securities, which mature in 2007, are guaranteed by TECO Energy. In December 2001, TECO Transport sold to a third party and leased back four vessels at its TECO Ocean Shipping subsidiary in a transaction structured as an operating lease with a term of 12 years, with an early termination option after year five. The $42.6 million of proceeds were used to repay short-term debt and for general corporate purposes.
TECO Power Services: In June 2001, TECO Power Services and its joint venture partner, Panda Energy, closed on a $2.175-billion syndicated bank financing for the construction of the Gila River and Union power stations. The financing includes $1.675 billion in five-year non-recourse debt and $500 million in equity bridge loans guaranteed by TECO Energy. Pricing for the non-recourse segment is 162.5 basis points over LIBOR during the construction period (first two years) and will increase to 175 basis points for year one of operation and 200 basis points for years two and three. If the projects secure an investment-grade rating the pricing will be reduced by 12.5 basis points. The equity bridge financing is repayable in four equal installments coincident with Phase 2 and Phase 4 completion of each project. The joint venture is a 50 percent owned unconsolidated affiliate; accordingly the debt is not included in TECO Energy's financial statements. The equity bridge financing includes two financial covenants, debt to capital and interest coverage requirements on a TECO Energy consolidated basis. The debt to capital as defined in the agreements must not exceed 65 percent at the end of each quarter and interest coverage as defined must equal or exceed 3.0 times for the twelve-month period ended each quarter. At Dec. 31, 2001, debt to capital was 62.2 percent and interest coverage was 4.2 times. In addition, this financing requires that TECO Energy maintain senior unsecured credit ratings not less than one rating of BBB and one rating of BBB-. Failure to meet these covenants would constitute a default event and the equity bridge financing would become due and payable. In March 2001, TPS converted the third-party construction financing for the Hamakua Power Station into a synthetic equipment operating lease with a term of five years. The lessor is an unaffiliated entity. As part of the transaction an unconsolidated affiliate of TPS loaned the lessor $12.8 million. In October 2000, TPS converted the construction debt relating to its San Jose project to $82 million of non-recourse financing, and issued $32 million of 10-year notes with a coupon rate of 9.63%. These notes are guaranteed by the Overseas Private Investment Corp. (OPIC). In December 2000, TPS sold to a third party, and entered into a synthetic operating lease for certain non-integral equipment at its Hardee Power Station with a 12-year term. The lessor is an unaffiliated entity.
- -------------------------------------------------------------------------------- FINANCIAL EXPOSURES TECO Energy is exposed to changes in interest rates primarily as a result of its borrowing activities. Based on the financing plans discussed in the Liquidity, Capital Resources section, a hypothetical 10% increase in TECO Energy's weighted average interest rate on its variable rate debt and required refinancings in 2002 would have an estimated $3.2 million impact on TECO Energy's earnings over the next fiscal year. A hypothetical 10% change in interest rates would not have a significant impact on the estimated fair value of TECO Energy's long-term debt at Dec. 31, 2001. Based on policies and procedures approved by the company's Board of Directors, from time to time TECO Energy enters into futures, swaps and option contracts to moderate its exposure to interest rate changes, to hedge the selling price for its physical production at TECO Coalbed Methane, to limit exposure to gas price increases at the regulated natural gas utility and to limit exposure to fuel price increases at TECO Transport. 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. TECO Power Services' energy marketing and trading subsidiary, TECO EnergySource, utilizes futures, swaps and option contracts in connection with the marketing of power in order to reduce the variability of electricity selling prices and to maximize the profitability of TPS' merchant power plant portfolio. Prior Energy Corporation, acquired by TECO Solutions in November 2001 (see TECO Solutions), and Peoples Gas services make use of physical and financial futures, swaps and options contracts in the normal course of its business. TECO Energy does not use derivatives or other financial instruments for speculative purposes.
________________________________________________________________________________ OFF BALANCE SHEET FINANCING Unconsolidated affiliates in which TECO Power Services has a 50% ownership interest or less have non-recourse project debt balances as follows at Dec. 31, 2001. This debt is recourse only to the unconsolidated affiliate, and TECO Energy has no debt payment obligations with respect to these financings.
- -------------------------------------------------------------------------------- Affiliate Affiliate Debt Balance (millions) TPS Ownership Interest - -------------------------------------------------------------------------------- Union & Gila River $683 50% EEGSA $200 24% Hamakua $ 86 50% - --------------------------------------------------------------------------------
The TECO/Panda debt balance is expected to reach $1.17 billion by the end of 2002 and $1.4 billion upon completion of construction of the Union and Gila River power stations. In addition, TECO Energy has guaranteed a $500 million equity bridge loan of the unconsolidated TECO/Panda affiliate, a TPS turbine lease financing facility of $69 million, and other debt-related items totaling $25 million. These facilities are not included in liabilities on TECO Energy's consolidated balance sheet, but do represent payment obligations of the company. At Dec. 31, 2001, TECO Energy had bank credit lines of $700 million, and Tampa Electric had bank credit lines of $300 million, all of which were undrawn and available. TECO Energy credit lines include a $250 million sublimit for letters of credit capacity. In January and February 2002, $141.7 million of letters of credit were issued against these lines, primarily related to the construction of the Union and Gila River power stations. These letters of credit of $69.5 million and $67.6 million for Union and Gila River, respectively, were replacements for the letters of credit posted by Enron and drawn by the TPS/Panda joint venture following Enron's bankruptcy filing. In addition, at Dec. 31, 2001 TECO Energy and its subsidiaries had $22 million of letters of credit outside of its bank credit line facility. TECO Energy guarantees certain current obligations of its operating companies in the normal course of business, the effects of which are included in the consolidated financial statements. At Dec. 31, 2001, such guarantees amounted to $173 million, primarily related to gas purchase and energy management activities of Prior Energy, TECO Gas Services, and TECO Power Services. As TPS' plants come on line, guarantees associated with gas purchases and power sales activities are expected to increase. The following table summarizes the letters of credit and guarantees outstanding, that are not included in the Summary of Cash Obligations table, except for the guarantees by TECO Energy for the performance of unconsolidated affiliates related to the construction of the Union and Gila River power stations estimated at $63 million (see Enron Exposure section).
(1) Expected final expiration date with annual renewals (2) Includes the expected maximum value of $154.3 million for letters of credit issued in January 2002 (3) May be renewed
- -------------------------------------------------------------------------------- LIQUIDITY, CAPITAL RESOURCES TECO Energy and its operating companies met cash needs during 2001 with a mix of internally generated funds, proceeds from the sale of equity and short- and long-term borrowings. It met cash needs during 2000 with a balance of internally generated funds, short- and long-term borrowings and retail trust preferred securities. In light of the accelerated equity commitments for the Union and Gila River projects under the bank financing plan, as discussed in the Enron Exposure section, and the capital requirements for committed regulated and unregulated projects, TECO Energy is exploring various options to strengthen its balance sheet. As a first step, the company has reduced its capital expenditure forecast for 2002 through 2004 by about $700 million primarily by delaying for an extended period generation projects that are not yet under construction for TPS and Tampa Electric, including the Bayside Units 3 and 4 repowering projects announced in the fall of 2001. Resumption of work on those projects will be evaluated periodically as market conditions evolve. TECO Energy estimates its incremental financing requirements, excluding non- recourse project debt at TPS, at approximately $650 million in 2002, and has debt maturities in 2002 totaling $788 million. The company issued $450 million of mandatorily convertible equity units in January 2002, (see Financing Section) and expects to issue common equity late in the year and long-term debt securities during the year. The company does not anticipate additional incremental financing requirements in the 2003 through 2004 period; however it expects to issue common equity in that time frame to reduce leverage. Notes payable, representing commercial paper with maturities up to 50 days, totaled $639 million at Dec. 31, 2001. The company reduced these balances to approximately $300 million in early 2002 with the proceeds of the mandatorily convertible securities issuance. TECO Energy provides short-term liquidity for its non-regulated operating companies primarily through its commercial paper program. Tampa Electric Company also issues commercial paper. These programs are backed by the bank credit line facilities. The company has identified in this Management's Discussion and Analysis (including in Investment Considerations below), several factors that could cause its operating cash flow to be lower than forecasted. Among these factors is the margins the company may realize for production from its merchant power facilities. Because of the company's recent expansion in the merchant power business, the company's cash flow has become increasingly dependent upon power margins. As a result, a decrease in these margins could result in external financing requirements that are higher than those forecasted above. The following table lists the obligations of TECO Energy and its subsidiaries for cash payments to repay debt, lease payments and unconditional commitments related to capital expenditures.
- -------------------------------------------------------------------------------- SUMMARY OF CASH OBLIGATIONS - -------------------------------------------------------------------------------- Payments Due by Period (millions) Total 2002 2003 2004 - 2006 After 2006 - -------------------------------------------------------------------------------- Long-term debt $2,597.0 $ 785.9 $ 104.6 $ 102.3 $ 1,604.2 Capital lease obligations 27.6 2.3 25.3 -- -- Operating leases/rentals 156.1 12.0 15.3 45.5 83.3 Unconditional purchase obligations/commitments 1,595.0 1,221.1 373.9 -- -- Other long-term obligstions 200.0 -- -- -- 200.0 - -------------------------------------------------------------------------------- Total cash obligations $4,575.7 $2,021.3 $ 519.1 $ 147.8 $ 1,887.5 - --------------------------------------------------------------------------------
- -------------------------------------------------------------------------------- TRANSACTIONS WITH RELATED AND CERTAIN OTHER PARTIES TECO Energy has interests in unconsolidated affiliates, which are discussed in the TECO Power Services, Other Unregulated Companies and Financing Activity sections. TECO Energy has certain transactions with its Directors and Officers that are reported in TECO Energy's annual proxy statement and Tampa Electric's annual regulatory filings. There are no material transactions of this type where the payments are in excess of those that would be paid under an arms-length transaction.
- -------------------------------------------------------------------------------- INVESTMENT CONSIDERATIONS The following are certain factors that could affect TECO Energy's future results. They should be considered in connection with evaluating forward-looking statements contained in this report and otherwise made by or on behalf of TECO Energy since these factors could cause actual results and conditions to differ materially from those projected in these forward-looking statements.
General Economic Conditions. The company's businesses are dependent on general economic conditions. In particular, the projected growth in Tampa Electric's service area and in Florida is important to the realization of Tampa Electric's and Peoples Gas System's forecasts for annual energy sales growth. An unanticipated downturn in the local area's or Florida's economy could adversely affect Tampa Electric's or Peoples Gas System's expected performance. The activities of the unregulated businesses, particularly TECO Transport, TECO Coal and TECO Power Services are also affected by general economic conditions in the respective industries and geographic areas they serve, both nationally and internationally. TPS' investment in EEGSA is dependent on growth in the service areas and forecasts for annual energy sales growth.
Weather Variations. Most of TECO Energy's businesses are affected by variations in general weather conditions and unusually severe weather. Tampa Electric's, Peoples Gas System's and TECO Power Services' energy sales are particularly sensitive to variations in weather conditions. The TECO Energy companies forecast energy sales on the basis of normal weather, which represents a long-term historical average. Significant variations from normal weather could have a material impact on energy sales. Unusual weather, such as hurricanes, could also have an effect on operating costs as well as sales. With a single winter peak period, Peoples Gas System is more weather sensitive than Tampa Electric, with both summer and winter peak periods. Mild winter weather in Florida can be expected to negatively impact results at Peoples Gas System. Variations in weather conditions also affect the demand and prices for the commodities sold by TECO Coalbed Methane and TECO Coal, as well as electric power sales from TECO Power Services' merchant power plants. TECO Transport also is impacted by weather because of its effects on the supply of and demand for the products transported. Severe weather conditions that could interrupt or slow service and increase operating costs also affect these businesses.
Potential Competitive Changes. The electric industry has been undergoing certain restructuring. Competition in wholesale power sales has been introduced on a national level. Some states have mandated or encouraged competition at the retail level, and in some situations required divestiture of generating assets. While there is active wholesale competition in Florida, the retail electric business has remained substantially free from direct competition. Changes in the competitive environment occasioned by legislation, regulation, market conditions or initiatives of other electric power providers, however, particularly with respect to retail competition, could adversely affect Tampa Electric's business and its performance. The gas distribution industry has been subject to competitive forces for several years. Gas services provided by Peoples Gas System are now unbundled for all non-residential customers. Because Peoples Gas System earns margins on distribution of gas, but not on the commodity itself, unbundling has not negatively impacted Peoples Gas System results. However, future structural changes cannot be predicted and could adversely affect Peoples Gas System.
Regulatory Actions. Tampa Electric and Peoples Gas System operate in highly regulated industries. Their retail operations, including the prices charged, are regulated by the FPSC, and Tampa Electric's wholesale power sales and transmission services are subject to regulation by the FERC. Changes in regulatory requirements or adverse regulatory actions could have an adverse effect on Tampa Electric's or Peoples Gas System's performance by, for example, increasing competition or costs, threatening investment recovery or impacting rate structure. The merchant plants being developed by TECO Power Services will require authorization from FERC for market-based rates. In granting such a request, FERC typically requires a showing that the plant's owners and affiliates lack market power in the relevant generation and transmission markets and in markets for related commerce such as fuel. Obtaining FERC authority for market-based rates would also require a showing by the seller that there is no opportunity for abusive affiliate transactions involving any of TECO Power Services' regulated affiliates. TECO Power Services does not anticipate any material difficulties in obtaining these authorizations, but it cannot guarantee that they will be granted. TECO Coal's forecast includes Section 29 tax credits related to the production of non-conventional fuels. Future changes law, regulation or administration could impact TECO Coal's quantity of qualified synfuel production, and therefore the amount of available tax credits.
Commodity Price Changes. Most of TECO Energy's businesses are sensitive to changes in certain commodity prices which could be brought on by many factors. Such changes could affect the prices these businesses charge, their operating costs and the competitive position of their products and services. In the case of Tampa Electric, currently fuel costs used for generation are mostly affected by the cost of coal; future fuel costs will be impacted by the cost of natural gas as well as 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. Regarding wholesale sales, the ability to make sales and the margins on power sales are currently affected by the cost of coal to Tampa Electric, particularly as it relates to the cost of gas and oil to other power producers. Results at TECO Power Services are impacted by changes in the market price for electricity. The profitability of merchant power plants is heavily dependent on the price for power in the markets they serve. Wholesale power prices are set by the market assuming a cost for the input energy and conversion efficiency but the fixed costs may not be reflected in the price for spot, or excess power. 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 System relative to electricity, other forms of energy and other gas suppliers. At the unregulated companies, changes in gas, oil and coal prices directly affect the margins at TECO Power Services, TECO Coalbed Methane, TECO Coal, and TECO Transport. TECO Coalbed Methane is exposed to commodity price risk through the sale of natural gas. A hypothetical 10-percent change for the year in the market price of natural gas would have an estimated earnings impact of $4 million. TECO Coal is exposed to commodity price risk through coal sales. A hypothetical 10-percent change in the market price of coal in any one year would have an estimated earnings impact of between $15 million and $20 million. TECO Transport is exposed to commodity price risk through fuel purchases. A hypothetical 10-percent change in the market price of fuel in any one year would have an estimated earnings impact of $1 million. Natural gas prices recently have been increasingly volatile, and thus the earnings from TECO Coalbed Methane are increasingly difficult to predict. At TECO Power Services, the price paid for natural gas is expected to pass through to the customer. In those instances where these costs are not passed directly to the customer, the price of gas is expected to be reflected in the price charged to the customer for electricity.
Gas Production Levels. Results at TECO Coalbed Methane are affected by its level of production, which is naturally declining. The company's forecast assumes that production will decline 8 percent annually. Actual production levels may be different than those assumed.
Tax Credits. TECO Energy derives a portion of its net income from non- conventional fuels tax credits. The realization of these tax credits are dependent on TECO Energy generating sufficient taxable income against which to use the credits, and these credits could be impacted by changes in law, regulation or administration.
Business growth opportunities. Part of the company's business strategy is to grow its unregulated businesses. Much of its growth is dependent on the ability to find attractive acquisition and development opportunities and independent power projects. The company's ability to successfully finance and complete current and future projects on schedule and within budget may also affect the success of this strategy. The company's outlook is based on its expectation that it will be successful in finding and capitalizing on these acquisition and development opportunities and independent power projects, but there can be no assurance that its efforts will be successful.
Construction and Development Risks. Tampa Electric currently has new power plants under construction and existing facilities under conversion and, TECO Power Services has new power plants under construction. The development of independent power plants involves considerable risks, including successful siting, permitting, financing and construction, contracting for necessary services, fuel supplies and power sales and performance by project partners. The construction of these plants, as well as future construction projects involves risks, such as shortages and inconsistent qualities of equipment; material and labor; engineering problems; work stoppages; unanticipated cost increases and environmental or geological problems.
Exposure to Enron. On December 2, 2001, Enron Corp., a large energy trading and services company, filed for protection under the U.S. Bankruptcy Code. TECO Energy believes that its exposure in operations from trade payables and other trading positions due to the Enron bankruptcy totals $3.5 million or less after tax at its subsidiaries, TECO Power Services (TPS), Peoples Gas System and Prior Energy, its new gas marketing subsidiary. An Enron subsidiary, NEPCO, is currently serving as the construction contractor for four merchant power stations in which TPS has interests. If NEPCO had to be replaced as contractor, it is likely that there would be delays in the project schedules and substantial additional project costs, including payment of added fees to a new contractor. A new contractor would also have to be reasonably satisfactory to the project lenders for the Union and Gila River projects.
Merchant Power Plants. TPS is currently operating, developing, constructing and investing in merchant power plants. A merchant plant sells power based on market conditions at the time of sale, so there can be no certainty at present about the amount or timing of revenue that may be received from power sales from operating plants or about the differential between the cost of operations (in particular, natural gas prices) and merchant power sales revenue. With no guaranteed rate of return, TPS will also have no guarantee that it will recover its initial investment in these plants. The company's forecast assumes that TPS will avoid losses associated with these risks by building in well-established markets that enable the company to use established hedging mechanisms, hiring experienced power marketers, entering into negotiated contracts with offtak-ers resulting in higher revenues than the spot market for capacity payment and ancillary services for a significant portion of the plant's output, avoiding selling short and entering into non-energy related sales to offset potential operational risks.
Operational Risks. Each of the company's subsidiaries is subject to various operational risks, including accidents or equipment breakdown or failure, and operations below expected levels of performance of efficiency. As operators of power generation facilities, Tampa Electric and TECO Power Services could incur problems such as the breakdown or failure of power generation equipment, transmission lines, pipelines or other equipment or processes which would result in performance below normal levels of output or efficiency. The company's forecast assumes normal operations and normal maintenance periods for its subsidiaries' facilities.
Interest Rates and Access to Capital. Changes in interest rates can affect the cost of borrowing for TECO Energy and its subsidiaries on variable rate debt outstanding, on refinancing of debt maturities and on incremental borrowing to fund new investments. Included in the company's forecasts is the expectation that it will have access to the equity and capital markets on satisfactory terms to fund growth opportunities, including acquisition and development opportunities and independent power projects.
Increased Debt Levels. To support its growth, the company has significantly expanded the amount of its indebtedness, increased its debt-to-equity ratio and lowered its interest coverage. This increase in debt levels has increased the amount of fixed charges the company is obligated to pay. The level of the company's indebtedness and restrictive covenants contained in existing or future financings could limit its ability to finance the acquisition and development of additional projects. In 2000 and 2001, Moody's Investor Services, Inc., Standard & Poor's Ratings Service and Fitch Investor Services, Inc. lowered the ratings on the debt securities of TECO Energy and Tampa Electric. The outlook assigned by each agency is negative. The ratings actions were attributed to increased debt levels and the changing risk profile associated with the expansion of TECO Energy's independent power development activities, as well as the required capital outlays of Tampa Electric, the uncertainties related to industry restructuring and the additional risks and obligations undertaken by TECO Energy with respect to various TPS projects. These downgrades and any further downgrades, may affect the company's ability to borrow and increase its financing cost which may decrease earnings.
Certain of the company's debt obligations contain financial covenants related to debt to equity ratios and interest coverage that could prevent the repayment of subordinated debt and the payment of dividends if such payments would cause a violation of the covenants. In addition, certain of the company's subsidiaries have indebtedness with restrictive covenants which, if violated, could prevent them from making distributions to TECO Energy. As a holding company, TECO Energy is dependent on cash flow from its subsidiaries.
International Risks. TECO Power Services is involved in several international projects. These projects involve numerous risks that are not present in domestic projects, including expropriation, political instability, currency exchange rate fluctuations, repatriation restrictions, and regulatory and legal uncertainties. The company's forecast assumes that TECO Power Services will avoid losses associated with these risks through a variety of risk mitigation measures, including specific contractual provisions, teaming with strong international and local partners, obtaining non-recourse financing and obtaining political risk insurance where appropriate. TECO Ocean Shipping is exposed to operational risks in international ports, primarily in the form of suitable labor and equipment to safely discharge its cargoes in a timely manner. The company's forecast assumes that TECO Ocean Shipping will avoid losses associated with these risks through a variety of risk mitigation measures, including retaining agents with local knowledge and experience in successfully discharging cargoes and vessels similar to those used.
Environmental Matters. TECO Energy's businesses are subject to regulation by various governmental authorities dealing with air, water and other environmental matters. Changes in compliance requirements or the interpretation by governmental authorities of existing requirements may impose additional costs on the company or result in the curtailment of some activities.
Item 7a.
Item 7a. Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk - ------------------
TECO Energy is exposed to changes in interest rates primarily as a result of its borrowing activities.
From time to time, TECO Energy or its affiliates may enter into futures, swaps and option contracts to moderate exposure to interest rate changes.
See the discussion of interest rate risk in the INVESTMENT CONSIDERATIONS sectio, and in the FINANCING ACTIVITY section.
Commodity Price Risk - --------------------
Currently, at Tampa Electric and Peoples Gas System, commodity price increases due to changes in market conditions for fuel, purchased power and natural gas are recovered through cost recovery clauses, with no effect on earnings.
TECO Coalbed Methane is exposed to commodity price risk through the sale of natural gas, TECO Coal is exposed to commodity price risk through coal sales, and TPS is exposed to commodity price risk through electricity and capacity sales, and heating oil purchases for its merchant plants.
From time to time, TECO Energy or its affiliates may enter into futures, swaps and options contracts to hedge the selling price for physical production at TECO Coalbed Methane, to limit exposure to gas price fluctuations for future purchases at Peoples Gas System and Prior Energy, to limit exposure to fuel price increases on future purchases at TECO Transport, or to limit exposure to electricity, and other commodity price fluctuations at TPS.
See the discussions of commodity price risks in the INVESTMENT CONSIDERATIONS -- COMMODITY PRICE CHANGES section.
TECO Energy and its affiliates do not currently use derivatives or other financial products for speculative purposes.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Index to Consolidated Financial Statements and Supplementary Data
All other financial statement schedules have been omitted since they are not required, are inapplicable or the required information is presented in the financial statements or notes thereto.
- -------------------------------------------------------------------------------- REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
- -------------------------------------------------------------------------------- TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF TECO ENERGY, INC., In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of TECO Energy, Inc. and its subsidiaries at Dec. 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended Dec. 31, 2001, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements and financial statement schedule in accordance with auditing standards generally accepted in the United States of America, 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 our opinion.
PricewaterhouseCoopers LLP
Tampa, Florida Jan. 11, 2002, except for the information in Note O as to which the dates are Jan. 23, 2002, Feb. 1, 2002 and Feb. 7, 2002
- -------------------------------------------------------------------------------- CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of the consolidated financial statements.
The accompanying notes are an integral part of the consolidated financial statements.
The accompanying notes are an integral part of the consolidated financial statements.
- -------------------------------------------------------------------------------- CONSOLIDATED STATEMENTS OF COMMON EQUITY - --------------------------------------------------------------------------------
The accompanying notes are an integral part of the consolidated financial statements. (1) TECO Energy had 400 million shares of $1 par value common stock authorized in 2001, 2000 and 1999.
- -------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------- A. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The significant accounting policies for both utility and diversified operations are as follows:
Principles of Consolidation The consolidated financial statements include the accounts of TECO Energy, Inc. (TECO Energy or the company) and its wholly owned subsidiaries. The equity method of accounting is used to account for investments in partnership arrangements in which TECO Energy or its subsidiary companies do not have majority ownership or exercise control. The proportional share of expenses, revenues and assets reflecting TECO Coalbed Methane's undivided interest in joint venture property is included in the consolidated financial statements. All significant intercompany balances and intercompany transactions have been eliminated in consolidation.
Basis of Accounting Tampa Electric and Peoples Gas System (the regulated utilities) maintain their accounts in accordance with recognized policies prescribed or permitted by the Florida Public Service Commission (FPSC). In addition, Tampa Electric maintains its accounts in accordance with recognized policies prescribed or permitted by the Federal Energy Regulatory Commission (FERC). These policies conform with generally accepted accounting principles in all material respects. The impact of Financial Accounting Standard (FAS) No. 71, Accounting for the Effects of Certain Types of Regulation, has been minimal in the experience of the regulated utilities, but when cost recovery is ordered over a period longer than a fiscal year, costs are recognized in the period that the regulatory agency recognizes them in accordance with FAS 71. Also, as provided in FAS 71, Tampa Electric has deferred revenues in accordance with the various regulatory agreements approved by the FPSC in 1995, 1996 and 1999. Revenues were recognized as allowed in 1997, 1998 and 1999 under the terms of the agreements. The regulated utilities' retail business is regulated by the FPSC, and Tampa Electric's wholesale business is regulated by FERC. Prices allowed, with respect to Tampa Electric, by both agencies are generally based on the recovery of prudent costs incurred plus a reasonable return on invested capital. The use of estimates is inherent in the preparation of financial statements in accordance with generally accepted accounting principles.
Revenues and Fuel Costs Revenues include amounts resulting from cost recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, 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 incurred and projected for a specific recovery period. Any over-recovery or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as deferred credits, and under-recoveries of costs are recorded as deferred charges. In 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. In February 1995, the FPSC authorized the recovery of this buy-out amount plus carrying costs through the Fuel and Purchased Power Cost Recovery Clause over the 10-year period beginning April 1, 1995. In each of the years 2001, 2000 and 1999, $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. Tampa Electric's objectives of stabilizing prices from 1996 through 1999 and securing fair earnings opportunities during this period were accomplished through a series of agreements entered into in 1996 with Florida's Office of Public Counsel (OPC) and the Florida Industrial Power Users Group (FIPUG) which were approved by the Florida Public Service Commission (FPSC). Prior to these agreements, the FPSC approved a plan submitted by Tampa Electric to defer certain 1995 revenues. In general, under these agreements Tampa Electric was allowed to defer revenues in 1995 and 1996 during the construction of Polk Unit 1 and recognize these revenues in 1997 and 1998 after commercial operation of the unit. Other components of the agreements were a base rate freeze through 1999 and refunds to customers totaling $50 million during the period October 1996 through December 1998 while Tampa Electric was allowed recovery of the capital costs incurred for the Polk Unit 1 project. As part of its series of agreements with OPC and FIPUG, Tampa Electric agreed to refund 60 percent of 1999 revenues that contributed to an ROE in excess of 12 percent, as calculated and approved by the FPSC. In October 2000, the FPSC staff recommended a 1999 refund of $6.1 million including interest, to be refunded to customers beginning January 2001. OPC objected to certain interest expenses recognized in 1999 that were associated with prior tax positions and used to calculate the amount to be refunded. Following a review by the FPSC staff, the FPSC agreed in December 2000 that the original $6.1 million was to be refunded to customers. On Feb. 7, 2001 OPC protested the FPSC's decision. The protest claimed that the stipulations did not allow for the inclusion of the interest expenses on income tax positions in the refund calculations. The FPSC held hearings on the issue in August 2001 and upheld its decision that the original refund amount plus interest was appropriate under the agreements. In January 2002, the OPC filed a motion with the FPSC asking for reconsideration of their decision alleging the Commission relied on erroneous information. Tampa Electric will begin making refunds to customers when the decision can no longer be appealed. The regulatory arrangements described above covered periods that ended on Dec. 31, 1999. Tampa Electric's rates and its allowed ROE range of 10.75 percent to 12.75 percent with a midpoint of 11.75 percent will continue in effect until such time as changes are occasioned by an agreement approved by the FPSC or other FPSC actions as a result of rate or other proceedings initiated by Tampa Electric, FPSC staff or other interested parties. Tampa Electric expects to continue earning within its allowed ROE.
Depreciation TECO Energy 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 4.2% for 2001, 4.1% for 2000 and 4.0% for 1999. The original cost of utility plant retired or otherwise disposed of and the cost of removal less salvage are charged to accumulated depreciation.
Goodwill and Intangible Assets Goodwill represents the excess of acquisition costs over the fair value of the net assets acquired in purchase transactions. Goodwill has been amortized on a straight-line basis over various periods not exceeding 40 years. On June 30, 2001, the Financial Accounting Standards Board finalized FAS 141, Business Combinations, and FAS 142, Goodwill and Other Intangible Assets. FAS 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method of accounting. With the adoption of FAS 142 effective Jan. 1,
2002, goodwill is no longer subject to amortization. Rather, goodwill will be subject to at least an annual assessment for impairment by applying a fair-value-based test. Under the new rules, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented, or exchanged, regardless of the acquirer's intent to do so. These intangible assets will be required to be amortized over their useful lives. The amount of goodwill included on the consolidated balance sheets at Dec. 31, 2001 and 2000, respectively, was $165.8 million and $93.1 million, net of accumulated amortization of $9.5 million and $4.7 million. Additions to goodwill in 2001 of $77.5 million resulted primarily from the acquisition of the Frontera Power Station and the purchase of Prior Energy. Amortization of goodwill included in the consolidated statements of income in 2001, 2000 and 1999 was $4.8 million, $2.7 million and $0.6 million, respectively. Adoption of FAS 142 effective Jan. 1, 2002 will result in the elimination of approximately $5 million of annual amortization. Under FAS 142, initial impairment testing should be completed within six months of adoption. TECO Energy is beginning the initial impairment testing of all goodwill, and does not anticipate an initial impairment charge upon adoption of FAS 142. The amount of intangible assets included in deferred charges and other assets on the consolidated balance sheet at Dec. 31, 2001 was $28.5 million, net of accumulated amortization of $12.3 million. This represents the value of customer backlog, supply agreements and the open cash flow hedges as of Nov. 1, 2001, related to the Prior Energy acquisition in November 2001 (see Note N). The company is amortizing the intangibles over the periods expected to benefit from these agreements, and recorded amortization expense of $12.3 million in 2001. Amortization expense for the remaining intangible value at Dec. 31, 2001 is expected to be $27.2 million in 2002 and $1.3 million in 2003. There were no intangible assets at Dec. 31, 2000.
Asset Impairment In August 2001, the Financial Accounting Standards Board issued FAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which supersedes FAS 121, Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of. FAS 144 addresses accounting and reporting for the impairment or disposal of long-lived assets, including the disposal of a segment of a business. FAS 144 is effective for fiscal years beginning after December 15, 2001. The company periodically assesses whether there has been a permanent impairment of its long-lived assets and certain intangibles held and used by the company, in accordance with FAS 121, and beginning in 2002 with FAS 144. The company does not anticipate that the adoption of FAS 144 will have a significant impact on its financial statements. In 2001, TECO Energy recorded after-tax charges of $7.2 million to adjust asset valuations. These adjustments included a $6.1 million after-tax charge recorded by TECO Power Services (TPS) related to the subsequent sale of TPS' minority interests in Energia Global International, Ltd. (EGI) which owns smaller power projects in Central America, and a $1.1 million after-tax charge to adjust the carrying value of leveraged leases at TECO Investments. In 2000, TECO Properties recorded an after-tax charge of $3.8 million to adjust property values. No write-down of assets due to impairment was required in 1999.
Reporting Comprehensive Income In 1999, the company adopted FAS 130, Reporting Comprehensive Income. This standard requires that comprehensive income, which includes net income as well as certain changes in assets and liabilities recorded in common equity, be reported in the financial statements. The company has reported accumulated other comprehensive income in its Consolidated Statements of Common Equity. TECO Energy reported the following comprehensive income (loss) in 2001, 2000 and 1999 related to changes in the fair value of cash flow hedges and adjustments to the minimum pension liability associated with the company's supplemental executive retirement plan:
- -------------------------------------------------------------------------------- COMPREHENSIVE INCOME (LOSS) - -------------------------------------------------------------------------------- (millions) 2001 2000 1999 - -------------------------------------------------------------------------------- Minimum pension liability $ 0.3 $ 2.0 $ (5.5) Cash flow hedges (19.2) -- -- - -------------------------------------------------------------------------------- Other comprehensive income (loss) (18.9) 2.0 (5.5) Net income 303.7 250.9 186.1 - -------------------------------------------------------------------------------- Total comprehensive income $284.8 $252.9 $180.6 ================================================================================
Reporting on the Costs of Start-up Activities In 1998, the AICPA issued Statement of Position (SOP) 98-5, Reporting on the Costs of Startup Activities. It requires costs of start-up activities and organization costs to be expensed as incurred. Start-up activities are broadly defined as those one-time activities related to events such as opening a new facility, conducting business in a new territory and organizing a new entity. Some costs, such as the costs of acquiring or constructing long-lived assets and bringing them into service, are not subject to SOP 98-5. Start-up costs, as defined by SOP 98-5, are expensed as incurred.
Accounting for Asset Retirement Obligations In July 2001, the Financial Accounting Standards Board finalized FAS 143, Accounting for Asset Retirement Obligations, which requires the recognition of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its present value and the related capitalized charge is depreciated over the useful life of the asset. FAS 143 is effective for fiscal years beginning after June 15, 2002. The company is currently reviewing the impact that FAS 143 will have on its results.
Foreign Operations The functional currency of the company's foreign investments is primarily the U.S. dollar. Transactions in the local currency are remeasured to the U.S. dollar for financial reporting purposes. The aggregate remeasurement gains or losses included in net income in 2001, 2000 and 1999 were not significant. The investments are generally protected from any significant currency gains or losses by the terms of the power sales agreements and other related contracts, in which payments are defined in U.S. dollars.
Deferred Income Taxes TECO Energy utilizes the liability method in the measurement of deferred income taxes. Under the liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at current tax rates. Tampa Electric and Peoples Gas System are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates.
Investment Tax Credits Investment tax credits have been recorded as deferred credits and are being amortized to income tax expense over the service lives of the related property.
Other Deferred Credits Other deferred credits primarily include the accrued post-retirement benefit liability, the pension liability and minority interest.
Allowance for Funds Used During Construction (AFUDC) AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric's cost of capital. The rate was 7.79% for 2001, 2000 and 1999. Total AFUDC for 2001, 2000 and 1999 was $9.2 million, $2.3 million and $1.8 million, respectively. The base on which AFUDC is calculated excludes construction work in progress which has been included in rate base.
Interest Capitalized Interest costs for the construction of non-utility facilities are capitalized and depreciated over the service lives of the related property. TECO Energy capitalized $23.0 million, $6.5 million and $2.7 million of interest costs in 2001, 2000 and 1999, respectively.
Cash Equivalents Cash equivalents are highly liquid, high-quality debt instruments purchased with an original maturity or three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.
Other Investments Other investments include longer-term passive investments. Other investments at Dec. 31, 2001 and 2000 were as follows:
- -------------------------------------------------------------------------------- Due (millions) Rate Date 2001 2000 - -------------------------------------------------------------------------------- Notes receivable from: Panda Energy 12% 12/31/02 $ 92.7 $ 92.7 Panda Energy 12% 2/28/01 -- 197.3 Energia Global Int'l (EGI) 15.4% 12/31/01 -- 23.2 Energia Global Int'l (EGI) 15% 3/31/01 -- 2.6 Mosbacher Power Partners L.P. 12% 8/1/08 13.1 13.0 Mosbacher Power Partners L.P. 9% 8/1/08 21.1 20.4 Mosbacher Power Partners L.P. 12% 10/4/06 6.2 4.8 EEGSA 7.89% (1) 9/11/07 10.9 10.9 TECO-Panda Generating Company, L.P. 7.33% (1) 11/30/04 37.5 -- TECO-Panda Generating Company, L.P. 6.65% (1) 11/30/04 86.7 -- Investment in Energy Center Kladno Generating (ECKG) (2) -- -- 18.2 18.2 Continuing Investments in Leveraged Leases -- -- 15.6 22.1 Other investments -- -- 1.1 0.8 - -------------------------------------------------------------------------------- 303.1 406.0 Current notes receivable 92.7 223.1 - -------------------------------------------------------------------------------- Other non-current investments $210.4 $182.9 ================================================================================
(1) Current rate at 12/31/01. (2) 13.35% ownership interest in an electric generating power project in the Czech Republic.
These financial investments have no quoted market prices and, accordingly, a reasonable estimate of fair market value could not be made without incurring excessive costs. However, the company believes by reference to stated interest rates and security description, the fair value of these assets would not differ significantly from the carrying value.
Investments in Unconsolidated Affiliates Investments in unconsolidated affiliates are accounted for using the equity method of accounting. At Dec. 31, 2001, these investments included TECO Propane Ventures' 38 percent ownership interest in US Propane, TPS' 24 percent ownership interest in EEGSA, the Guatemalan electric utility, TPS' 50 percent voting interest in the TECO-Panda Generating Company L.P., TPS' 50 percent ownership interest in the Hamakua Power Station in Hawaii and TECO Properties' 50 percent ownership interest in six real estate projects. At Dec. 31, 2000, the investment in unconsolidated affiliates included the US Propane, EEGSA, Hamakua and real estate investments as well as TPS' 33.68 percent ownership interest in EGI. Summary financial information for TECO-Panda Generating Company, L.P., a development stage enterprise, as of Dec. 31, 2001 and 2000 is presented in the following table. There were no revenues for the year ended Dec. 31, 2001 and for the period of inception through Dec. 31, 2000. Results from operations were not material for these periods.
- -------------------------------------------------------------------------------- (millions) Dec. 31, 2001 Dec. 31, 2000 - -------------------------------------------------------------------------------- Current assets $ 102.6 $ 1.3 Non-current assets $1,857.4 $ 217.9 Current liabilities $ 209.6 $ 231.9 Non-current liabilities $1,844.0 $ -- - --------------------------------------------------------------------------------
Coalbed Methane Gas Properties TECO Coalbed Methane, a subsidiary of TECO Energy, has developed jointly the natural gas potential in a portion of Alabama's Black Warrior Basin. TECO Coalbed Methane utilizes the successful efforts method to account for its gas operations. Under this method, expenditures for unsuccessful exploration activities are expensed currently. Capitalized costs are amortized on the unit-of-production method using estimates of proven reserves. Investments in unproven properties and major development projects are not amortized until proven reserves associated with the projects can be determined or until impairment occurs. Aggregate capitalized costs related to producing wells at Dec. 31, 2001 and 2000 were $220.8 million and $216.2 million, respectively. Net proven reserves at Dec. 31, 2001 and 2000 were as follows:
- -------------------------------------------------------------------------------- NET PROVEN RESERVES - COALBED METHANE GAS - -------------------------------------------------------------------------------- (billion cubic feet) 2001 2000 - -------------------------------------------------------------------------------- Proven reserves, beginning of year 181.7 159.1 Production (15.0) (15.7) Revisions of previous estimates 0.4 38.3 - -------------------------------------------------------------------------------- Proven reserves, end of year 167.1 181.7 - -------------------------------------------------------------------------------- Number of wells 682 700 - --------------------------------------------------------------------------------
Accounting for Derivative Instruments, Hedging and Energy Trading Effective January 1, 2001, the company adopted Financial Accounting Standard (FAS) 133, Accounting for Derivative Instruments and Hedging. The new standard requires the company to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value, and to reflect the changes in fair value of those instruments as either components of comprehensive income or in net income, depending on the types of those instruments. At adoption, the company had derivatives in place at TECO Coalbed Methane that qualified for cash flow hedge accounting treatment under FAS 133, and recorded an opening swap liability of $19.0 million and an after-tax reduction to other comprehensive income of $12.6 million.
At the time derivative contracts are entered into, the company determines whether the derivative is subject to the requirements of FAS 133 or meets criteria for exclusion such as for certain normal purchases and sales activity. All contracts requiring FAS 133 accounting are designated as a cash flow hedge, fair value hedge or as a trading instrument, and formal documentation of relationships between hedging instruments and the hedged items, hedging objective and strategy, and methods for assessing hedge effectiveness both at the hedge's inception and on an ongoing basis is completed. From time to time, TECO Energy enters into futures, swaps and options contracts to hedge the future selling price for its physical production at TECO Coalbed Methane, to limit exposure to gas price fluctuations for future purchases at Peoples Gas System and at Prior Energy, to limit exposure to interest rate fluctuations at TECO Energy and other affiliates, to limit exposure to electricity and other commodity fluctuations at TECO Power Services, and to limit exposure to fuel price increases on future purchases at TECO Transport. As such, most of the company's derivative activity that cannot be excluded from the requirements of FAS 133 receives cash flow hedge accounting treatment. Cash Flow Hedges: For the year ended Dec. 31, 2001, the company recognized a loss of $19.7 million for the cash flow hedges that were settled. Of this amount, $6.5 million was reported as a reduction to revenue related to hedges of future sales at TECO Coalbed Methane, and $13.2 million was reported as operating expenses related to hedges of future gas purchases at Peoples Gas and Prior Energy. As of Dec. 31, 2001, the company had open hedging transactions that qualify for cash flow hedge accounting treatment at Prior Energy, TECO Coalbed Methane, Peoples Gas and TECO Transport with a net pretax liability fair value of $29.5 million. Of this total, $28.2 million is expected to be reclassified to earnings within the next twelve months on instruments with maturity dates throughout 2002 when the related future transactions take place. Unrealized after tax losses on all open cash flow hedges of $8.1 million were recorded as a reduction to other comprehensive income. An additional $17.4 million representing open cash flow hedges prior to the Nov. 1, 2001 acquisition of Prior Energy were recorded as a deferred charge. The company, through its TECO Power Services subsidiary, has an equity investment in a partnership with Panda Energy. The partnership utilizes interest rate swap agreements to effectively convert a portion of its floating rate debt to a fixed rate basis, thereby reducing the impact of interest rate changes on construction costs and future income. On the interest rate swap agreements, the partnership pays a fixed rate and receives a variable rate based on London Interbank Offered Rate (LIBOR), with terms ranging from 2 to 5 years. At Dec. 31, 2001, the company recorded $11.2 million for its equity portion of the unrealized losses on these cash flow hedge swaps reflecting the sharp decline in floating interest rates since the inception of the swap agreements as a reduction to other comprehensive income and a corresponding reduction to the investment account. Fair Value Hedges: For the year ended Dec. 31, 2001, the company recognized gains of $0.1 million as operating expenses for changes in the fair value of derivatives classified as fair value hedges. As of Dec. 31, 2001, the company had open hedging transactions against gas storage inventory at Prior Energy that qualify for fair value hedge accounting treatment with a net derivative asset pretax value of $0.9 million, all of which is expected to be reclassified to earnings within the next twelve months. Trading Derivatives: The company has entered into a limited number of financial derivatives at its TECO Power Services and Prior Energy affiliates which do not qualify for hedge accounting treatment under FAS 133. TECO Power Services has a capacity call option, which is marked-to-market. The fair value of these options is determined using an industry standard model from the Financial Engineering Association which is based on the Black-Scholes valuation model and evaluates current prices, volatility of prices, and time to expiration of the options. For the year ended Dec. 31, 2001, the company recognized a pretax loss of $0.8 million for the decrease in fair value on these options. As of Dec. 31, 2001, the $1.5 million fair value of these options is included in current assets, all of which is expected to be realized within the next twelve months. As of Dec. 31, 2001, Prior Energy had several open swap and option positions where they acted as the counterparty to the transactions. These contracts are marked-to-market under FASB's Emerging Issues Task Force (EITF) release Issue 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The fair value of these derivatives is determined using the Henry Hub Natural Gas futures prices as actively quoted on New York Mercantile Exchange (NYMEX). For the year ended Dec. 31, 2001, the company recognized $0.7 million in pretax losses related to these derivatives. As of Dec. 31, 2001, $7.5 million of pretax fair value of open liability positions is offset by $7.4 million of open asset positions, all of which are expected to be realized within the next twelve months.
Reclassifications Certain prior year amounts were reclassified to conform with current year presentation.
- -------------------------------------------------------------------------------- B. COMMON STOCK
Stock-Based Compensation In April 1996, the shareholders approved the 1996 Equity Incentive Plan (the "1996 Plan"). The 1996 Plan superseded the 1990 Equity Incentive Plan (the "1990 Plan"), and no additional grants will be made under the 1990 Plan. The rights of the holders of outstanding options under the 1990 Plan were not affected. The purpose of the 1996 Plan is to attract and retain key employees of the company, to provide an incentive for them to achieve long-range performance goals and to enable them to participate in the long-term growth of the company. The 1996 Plan amended the 1990 Plan to increase the number of shares of common stock subject to grants by 3,750,000 shares, expand the types of awards available to be granted and specify a limit on the maximum number of shares with respect to which stock options and stock appreciation rights may be made to any participant under the plan. Under the 1996 Plan, the Compensation Committee of the Board of Directors may award stock grants, stock options and/or stock equivalents to officers and key employees of TECO Energy and its subsidiaries. The Compensation Committee has discretion to determine the terms and conditions of each award, which may be subject to conditions relating to continued employment, restrictions on transfer or performance criteria. In 2001, under the 1996 Plan, 1,268,486 stock options were granted, with a weighted average option price of $31.39 and a maximum term of 10 years. In addition, 183,260 shares of restricted stock were awarded, each with a weighted average fair value of $31.575. Compensation expense recognized for stock grants awarded under the 1996 Plan was $2.8 million, $4.6 million and $1.6 million in 2001, 2000 and 1999, respectively. The stock grants awarded in 2001, 2000 and 1999 are primarily performance shares, restricted subject to meeting specified total shareholder return goals, vesting in three years with final payout ranging from zero to 200% of the original grant. Adjustments are made currently to reflect contingent shares which could be issuable based on current period results. The consolidated balance sheets at Dec. 31, 2001 and 2000 reflected a $1.1 million and a $5.5 million liability respectively, classified as other deferred credits, for these contingent shares. The remaining stock grants are restricted subject generally to continued employment, with the 1998 stock grants vesting in five years and the 1997 and 1996 stock grants vesting at normal retirement age. In April 2001, the shareholders approved an amendment to the 1996 Plan, to increase the number of shares of common stock subject to grants by 6.3 million. Stock option transactions during the last three years under the 1996 Plan and the 1990 Plan (collectively referred to as the "Equity Plans") are summarized as follows:
- -------------------------------------------------------------------------------- STOCK OPTIONS - EQUITY PLANS - -------------------------------------------------------------------------------- Option Shares Weighted Avg. (thousands) Option Price - -------------------------------------------------------------------------------- Balance at Dec. 31, 1998 2,732 $23.06 Granted 1,158 $21.54 Exercised (32) $16.58 Cancelled (31) $24.32 - -------------------------------------------------------------------------------- Balance at Dec. 31, 1999 3,827 $22.64 Granted 1,264 $21.33 Exercised (488) $20.15 Cancelled (44) $23.61 - -------------------------------------------------------------------------------- Balance at Dec. 31, 2000 4,559 $22.54 Granted 1,268 $31.39 Exercised (605) $21.53 Cancelled (32) $26.88 - -------------------------------------------------------------------------------- Balance at Dec. 31, 2001 5,190 $24.79 ================================================================================ Exercisable at Dec. 31, 2001 2,068 $21.88 Available for future grant at Dec. 31, 2001 6,262 - --------------------------------------------------------------------------------
As of Dec. 31, 2001, the 5.2 million options outstanding under the Equity Plans are summarized below.
- -------------------------------------------------------------------------------- STOCK OPTIONS OUTSTANDING AT DEC. 31, 2001 - -------------------------------------------------------------------------------- Option Shares Range of Weighted Avg. Weighted Avg. Remaining (thousands) Option Prices Option Price Contractual Life - -------------------------------------------------------------------------------- 2,566 $18.84-$22.48 $21.08 7 Years 744 $23.55-$25.97 $24.05 4 Years 1,880 $27.56-$31.58 $30.15 8 Years ================================================================================
In April 1997, the Shareholders approved the 1997 Director Equity Plan (the "1997 Plan"), as an amendment and restatement of the 1991 Director Stock Option Plan (the "1991 Plan"). The 1997 Plan supersedes the 1991 Plan, and no additional grants will be made under the 1991 Plan. The rights of the holders of outstanding options under the 1991 Plan will not be affected. The purpose of the 1997 Plan is to attract and retain highly qualified non-employee directors of the company and to encourage them to own shares of TECO Energy common stock. The 1997 Plan is administered by the Board of Directors. The 1997 Plan amended the 1991 Plan to increase the number of shares of common stock subject to grants by 250,000 shares, expanded the types of awards available to be granted and replaced the current fixed formula grant by giving the Board discretionary authority to determine the amount and timing of awards under the Plan. In 2001, 35,000 options were granted, with a weighted average option price of $31.26. Transactions during the last three years under the 1997 Plan are summarized as follows:
- -------------------------------------------------------------------------------- STOCK OPTIONS - DIRECTOR EQUITY PLANS - -------------------------------------------------------------------------------- Option Shares Weighted Avg. (thousands) Option Price - -------------------------------------------------------------------------------- Balance at Dec. 31, 1998 241 $21.22 Granted 32 $21.51 Exercised -- -- Cancelled -- -- - -------------------------------------------------------------------------------- Balance at Dec. 31, 1999 273 $21.25 Granted 30 $23.49 Exercised (33) $18.57 Cancelled (12) $25.15 - -------------------------------------------------------------------------------- Balance at Dec. 31, 2000 258 $21.68 Granted 35 $31.26 Exercised (91) $19.12 Cancelled -- -- - -------------------------------------------------------------------------------- Balance at Dec. 31, 2001 202 $24.49 ================================================================================ Exercisable at Dec. 31, 2001 142 $22.27 Available for future grant at Dec. 31, 2001 302 - --------------------------------------------------------------------------------
As of Dec. 31, 2001, the 202,000 options outstanding under the 1997 Plan with option prices of $18.53-$31.575, had a weighted average option price of $24.49 and a weighted average remaining contractual life of six years. TECO Energy has adopted the disclosure-only provisions of FAS 123, Accounting for Stock-Based Compensation, but applies Accounting Principles Board Opinion No. 25 and related interpretations in accounting for its plans. Therefore, since stock options are granted with an option price greater than or equal to the fair value on date of grant, no compensation expense has been recognized for stock options granted under the 1996 Plan and the 1997 Plan. If the company had elected to recognize compensation expense for stock options based on the fair value at grant date, consistent with the method prescribed by FAS 123, net income and earnings per share would have been reduced to the pro forma amounts shown below. These pro forma amounts were determined using the Black-Scholes valuation model with weighted average assumptions as shown below.
- -------------------------------------------------------------------------------- 2001 2000 1999 - -------------------------------------------------------------------------------- Net Income from As reported $303.7 $250.9 $200.9 continuing operations (millions) Pro forma $298.6 $247.8 $198.5 - -------------------------------------------------------------------------------- Net Income (millions) As reported $303.7 $250.9 $186.1 Pro forma $298.6 $247.8 $183.7 - --------------------------------------------------------------------------------
Net Income from continuing operations As reported $ 2.26 $ 1.99 $ 1.53 - - EPS basic Pro forma $ 2.22 $ 1.97 $ 1.52 - -------------------------------------------------------------------------------- Net Income As reported $ 2.26 $ 1.99 $ 1.42 - - EPS basic Pro forma $ 2.22 $ 1.97 $ 1.40 - -------------------------------------------------------------------------------- Assumptions Risk-free interest rate 4.86% 6.24% 5.26% Expected lives (in years) 6 6 6 Expected stock volatility 27.45% 22.93% 19.14% Dividend yield 5.46% 5.15% 4.55% - --------------------------------------------------------------------------------
Dividend Reinvestment Plan In 1992, TECO Energy implemented a Dividend Reinvestment and Common Stock Purchase Plan (DRP). TECO Energy raised $8.6 million and $8.1 million of common equity from this plan in 2001 and 2000, respectively. In 1999 the DRP purchased shares of TECO Energy common stock on the open market for plan participants.
Common Stock and Treasury Stock In September 1999, TECO Energy began a program to repurchase up to $150 million of its outstanding common stock. Shares acquired constituted treasury shares. In 1999 and 2000, the company acquired 7.0 million shares of its outstanding common stock at a cost of $144.7 million, or an average per share price of $20.55. The company's share repurchase program favorably impacted earnings in 2000 by approximately $0.06 per share. Earnings per share results were not significantly affected in 1999 because the purchases occurred late in the year. On March 12, 2001, the company completed a public offering of 8.625 million common shares at $27.75 per share, 7.0 million shares of which were reissued from Treasury shares. On Oct. 4, 2001, Standard and Poor's (S&P) announced the inclusion of TECO Energy shares in the S&P 500 index effective as of the market close on Oct. 9, 2001. On Oct. 12, 2001, TECO Energy issued 3.5 million additional common shares at $26.72 per share. The sales of the common shares resulted in total net proceeds to TECO Energy of $325.5 million in 2001, which were used to fund capital expenditures, for working capital requirements, general corporate purposes and to repay short-term debt.
Shareholder Rights Plan In accordance with the company's Shareholder Rights Plan, a Right to purchase one additional share of the company's common stock at a price of $90 per share is attached to each outstanding share of the company's common stock. The Rights expire in May 2009, subject to extension. The Rights will become exercisable 10 business days after a person acquires 10 percent or more of the company's outstanding common stock or commences a tender offer that would result in such person owning 10 percent or more of such stock. If any person acquires 10 percent or more of the outstanding common stock, the rights of holders, other than the acquiring person, become rights to buy shares of common stock of the company (or of the acquiring company if the company is involved in a merger or other business combination and is not the surviving corporation) having a market value of twice the exercise price of each Right. The company may redeem the Rights at a nominal price per Right until 10 business days after a person acquires 10 percent or more of the outstanding common stock.
Employee Stock Ownership Plan Effective Jan. 1, 1990, TECO Energy amended the TECO Energy Group Retirement Savings Plan, a tax-qualified benefit plan available to substantially all employees, to include an employee stock ownership plan (ESOP). During 1990, the ESOP purchased 7 million shares of TECO Energy common stock on the open market for $100 million. The share purchase was financed through a loan from TECO Energy to the ESOP. This loan is at a fixed interest rate of 9.3% and will be repaid from dividends on ESOP shares and from TECO Energy's contributions to the ESOP. TECO Energy's contributions to the ESOP were $5.6 million, $6.8 million, and $7.5 million in 2001, 2000 and 1999, respectively. TECO Energy's annual contribution equals the interest accrued on the loan during the year plus additional principal payments needed to meet the matching allocation requirements under the plan, less dividends received on the ESOP shares. The components of net ESOP expense recognized for the past three years are as follows:
- -------------------------------------------------------------------------------- (millions) 2001 2000 1999 - -------------------------------------------------------------------------------- Interest expense $ 5.2 $ 6.0 $ 6.9 Compensation expense 7.4 6.9 7.5 Dividends (8.5) (8.5) (8.4) - -------------------------------------------------------------------------------- Net ESOP expense $ 4.1 $ 4.4 $ 6.0 ================================================================================
Compensation expense was determined by the shares allocated method. At Dec. 31, 2001, the ESOP had 3.4 million allocated shares, 0.2 million committed-to-be-released shares, and 2.6 million unallocated shares. Shares are released to provide employees with the company match in accordance with the terms of the TECO Energy Group Retirement Savings Plan and in lieu of dividends on allocated ESOP shares. The dividends received by the ESOP are used to pay debt service. For financial statement purposes, the unallocated shares of TECO Energy stock are reflected as a reduction of common equity, classified as unearned compensation. Dividends on all ESOP shares are recorded as a reduction of retained earnings, as are dividends on all TECO Energy common stock. The tax benefit related to the dividends paid to the ESOP for allocated shares is a reduction of income tax expense and for unallocated shares is an increase in retained earnings. All ESOP shares are considered outstanding for earnings per share computations.
- -------------------------------------------------------------------------------- C. REDEEMABLE PREFERRED SECURITIES In November 2000, TECO Energy established TECO Capital Trust I (the Trust) for the sole purpose of issuing Trust Preferred Securities (TRuPS) and using the proceeds to purchase company preferred securities from TECO Funding I, LLC (TECO Funding). On Dec. 20, 2000, the Trust issued 8 million shares of $25 par, 8.5% TRuPS, due 2041, with an aggregate liquidation value of $200 million. Currently, all 8 million shares of the TRuPS are outstanding. Each TRuPS represents an undivided beneficial interest in the assets of the Trust. The Trust used the proceeds from the sale of the TRuPS to purchase a corresponding amount of company preferred securities of TECO Funding. TECO Funding used the proceeds from the sale of the company preferred securities to the Trust of $200 million and the sale of $6.2 million of its common securities to TECO Energy, to purchase $206.2 million of 8.5% junior subordinated notes of TECO Energy, due 2041. The junior subordinated notes are the sole assets of TECO Funding and the company preferred securities are the sole assets of the Trust. TECO Energy's proceeds from the sale of the junior subordinated notes were used to reduce the commercial paper balances of TECO Finance and for general corporate purposes. TECO Energy has guaranteed the payments to the holders of the company preferred securities and indirectly, the payments to the holders of the TRuPS, as a result of their beneficial interest in the company preferred securities. Distributions are payable quarterly in arrears on January 31, April 30, July 31, and October 31 of each year. Distributions were $17.0 million in 2001. No distributions were made in 2000. The junior subordinated notes may be redeemed at the option of TECO Energy at any time on or after Dec. 20, 2005 at 100% of their principal amount plus accrued interest through the redemption date. If TECO Energy redeems the junior subordinated notes in full before their maturity date, then TECO Funding is required to redeem the company preferred securities and common securities, in accordance with their terms. If TECO Energy redeems the junior subordinated notes in part but not in full before their maturity date, then TECO Funding will redeem the company preferred securities in full prior to any payment being made on the common securities. Upon any liquidation of the company preferred securities, holders of the TRuPS would be entitled to the liquidation preference of $25 per share plus all accrued and unpaid dividends through the date of redemption.
- -------------------------------------------------------------------------------- D. PREFERRED STOCK
Preferred stock of TECO Energy - $1 par 10 million shares authorized, none outstanding.
Preference stock of Tampa Electric - no par 2.5 million shares authorized, none outstanding.
Preferred stock of Tampa Electric - no par 2.5 million shares authorized, none outstanding.
Preferred Stock of Tampa Electric -- $100 par value 1.5 million shares authorized, none outstanding.
(1) Composite year-end interest rate. (2) These notes are subject to mandatory tender on Oct. 1, 2002, at which time they will be redeemed or remarketed. (3) These notes are subject to redemption in whole or in part, at any time, at the option of the company. (4) These notes are callable at par on or after Nov. 15, 2001. (5) Tax-exempt securities. (6) Proceeds of these bonds were used to refund bonds with interest rates of 11.625%-12.625%. 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. (7) 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. (8) These notes are subject to mandatory tender on Sept. 1, 2002, at which time they will be redeemed or remarketed. (9) 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. (10) Of the amount due in 2002, $0.8 million may be satisfied by the substitution of property in lieu of cash payments.
TECO Transport entered into a capital lease agreement with Midwest Marine Management Company in March 1998 for the charter of additional capacity. This lease covers 110 river barges and three towboats, classified as property, plant and equipment on the balance sheet; the corresponding $35 million five-year lease commitment was recorded as long-term debt on the balance sheet. The following is a schedule of future minimum lease payments under the capitalized lease together with the present value of the net minimum lease payments as of Dec. 31, 2001:
- -------------------------------------------------------------------------------- Year ended Dec. 31: Amount (millions) - -------------------------------------------------------------------------------- 2002 $ 4.6 2003 25.8 - -------------------------------------------------------------------------------- Total minimum lease payments 30.4 Less: Amount representing interest 2.8 - -------------------------------------------------------------------------------- Present value of net minimum lease payments, including current maturities of $2.3 million $ 27.6 ================================================================================
Substantially all of the property, plant and equipment of Tampa Electric is pledged as collateral to secure its long-term debt. TECO Energy's maturities and annual sinking fund requirements of long-term debt for the years 2003, 2004, 2005 and 2006 are $129.9 million, $31.6 million, $34.2 million and $36.5 million, respectively. Of these amounts $0.8 million per year for 2003 through 2006 may be satisfied by the substitution of property in lieu of cash payments. At Dec. 31, 2001, total long-term debt had a carrying amount of $1,842.5 million and an estimated fair market value of $1,966.0 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.
- -------------------------------------------------------------------------------- F. SHORT-TERM DEBT Notes payable consisted primarily of commercial paper with weighted average interest rates of 1.99% and 6.53%, at Dec. 31, 2001 and 2000, respectively. The carrying amount of notes payable approximated fair market value because of the short maturity of these instruments. The company has in place a $1 billion syndicated line of credit facility, comprised of $700 million for TECO Energy and $300 million for Tampa Electric Company. There were no borrowings outstanding at Dec. 31, 2001. These lines of credit require commitment fees ranging from .08% to .13% on the unused balances. Within this $1 billion facility, TECO Energy has $250 million of capacity to issue letters of credit. See Note O for January and February 2002 activity related to these letters of credit.
- -------------------------------------------------------------------------------- G. EMPLOYEE POSTRETIREMENT BENEFITS
Pension Benefits TECO Energy has a non-contributory defined benefit retirement plan which covers substantially all employees. Benefits are based on employees' age, years of service and final average earnings. On April 1, 2000, the plan was amended to provide for benefits to be earned and payable substantially on a lump sum basis through an age and service credit schedule for eligible participants leaving the company on or after July 1, 2001. Other significant provisions of the plan, such as eligibility, definitions of credited service, final average earnings, etc., were largely unchanged. This amendment resulted in decreased pension expense of approximately $.8 million and $2.0 million in 2001 and 2000, respectively, and a reduction of benefit obligation of $6.2 million and $14.4 million at Sept. 30, 2001 and Dec. 31, 2000, respectively. The company'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 60 percent of plan assets were invested in common stock and 40 percent in fixed income investments at Sept. 30, 2001. Amounts shown also include the unfunded obligations for the supplemental executive retirement plans, non-qualified, non-contributory defined benefit retirement plans available to certain senior management. TECO Energy reported $0.3 million and $2 million of comprehensive income in 2001 and 2000, respectively, and $5.5 million of comprehensive loss in 1999 related to adjustments to the minimum pension liability associated with the supplemental executive retirement plan. In 2001, TECO Energy elected to change the measurement date for pension obligations and plan assets from Dec. 31 to Sept. 30. The effect of this accounting change is not material.
Other Postretirement Benefits TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits for substantially all employees retiring after age 55 meeting certain service requirements. The company contribution toward health care coverage for most employees who retired after Jan. 1, 1990 and before July 1, 2001, is limited to a defined dollar benefit based on years of service. On April 1, 2000, the company adopted changes to this program for participants retiring from the company on or after July 1, 2001, after age 50 that meet certain service requirements. The company contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after July 1, 2001, is limited to a defined dollar benefit based on an age and service schedule. The impact of this amendment, including a change in the company's commitment for future retirees combined with a grandfathering provision for current retired participants, resulted in a reduction in the benefit obligation of $1.4 million in 2001 and an increase of $22.9 million in 2000. Postretirement benefit levels are substantially unrelated to salary. The company reserves the right to terminate or modify the plans in whole or in part at any time. In 2001, TECO Energy elected to change the measurement date for benefit obligations from Dec. 31 to Sept. 30. The effect of this accounting change is not material.
The following charts summarize the income statement and balance sheet impact, as well as the benefit obligations, assets, funded status and rate assumptions associated with the pension and other postretirement benefits.
The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for non-qualified pension plans with accumulated benefit obligations in excess of plan assets were $27.3 million, $23.5 million and $0 respectively as of Sept. 30, 2001 and $26.1 million, $23.0 million and $0 as of Dec. 31, 2000.
The assumed health care cost trend rate for medical costs prior to age 65 was 5.5% in 2001 and decreases to 5.0% in 2002 and thereafter. The assumed health care cost trend rate for medical costs after age 65 was 5.3% in 2001 and decreases to 5.0% in 2002 and thereafter. A 1 percent increase in the medical trend rates would produce an 8 percent ($1.1 million) increase in the aggregate service and interest cost for 2001 and an 8 percent ($12.0 million) increase in the accumulated postretirement benefit obligation as of Sept. 30, 2001. A 1 percent decrease in the medical trend rates would produce a 5 percent ($0.7 million) decrease in the aggregate service and interest cost for 2001 and a 4 percent ($6.3 million) decrease in the accumulated postretirement benefit obligation as of Sept. 30, 2001.
- -------------------------------------------------------------------------------- H. INCOME TAX EXPENSE Income tax expense consists of the following components: - -------------------------------------------------------------------------------- (millions) Federal State Total - -------------------------------------------------------------------------------- Currently payable $ 77.8 $ 19.9 $ 97.7 Deferred (95.5) (7.4) (102.9) Amortization of investment tax credits (4.9) -- (4.9) - -------------------------------------------------------------------------------- Total income tax expense $ (22.6) $ 12.5 $ (10.1) - --------------------------------------------------------------------------------
- -------------------------------------------------------------------------------- Currently payable $ 92.6 $ 8.4 $ 101.0 Deferred (81.1) 3.5 (77.6) Amortization of investment tax credits (4.9) -- (4.9) - -------------------------------------------------------------------------------- Total income tax expense $ 6.6 $ 11.9 $ 18.5 - --------------------------------------------------------------------------------
- -------------------------------------------------------------------------------- Currently payable $ 89.6 $ 13.0 $ 102.6 Deferred (11.5) 1.1 (10.4) Amortization of investment tax credits (5.2) -- (5.2) - -------------------------------------------------------------------------------- Income tax expense from continuing operations 72.9 14.1 87.0 - -------------------------------------------------------------------------------- Currently payable (3.6) (0.3) (3.9) Deferred (4.4) (0.5) (4.9) - -------------------------------------------------------------------------------- Income tax benefit from discontinued operations (8.0) (0.8) (8.8) - -------------------------------------------------------------------------------- Total income tax expense $ 64.9 $ 13.3 $ 78.2 - --------------------------------------------------------------------------------
Deferred taxes result from temporary differences in the recognition of certain liabilities or assets for tax and financial reporting purposes. The principal components of the company's deferred tax assets and liabilities recognized in the balance sheet are as follows:
- -------------------------------------------------------------------------------- (millions) Dec. 31, 2001 2000 - -------------------------------------------------------------------------------- Deferred income tax assets (1) Property related $ 87.7 $ 77.6 Basis differences in oil and gas producing properties 1.2 1.2 Alternative minimum tax credit carry forward 105.5 58.1 Other 47.6 37.5 - -------------------------------------------------------------------------------- Total deferred income tax assets 242.0 174.4 - -------------------------------------------------------------------------------- Deferred income tax liabilities (1) Property related (522.8) (499.4) Basis differences in oil and gas producing properties (8.9) (11.0) Other 33.0 7.1 - -------------------------------------------------------------------------------- Total deferred income tax liabilities (498.7) (503.3) - -------------------------------------------------------------------------------- Accumulated deferred income taxes $ (256.7) $ (328.9) - --------------------------------------------------------------------------------
(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) 2001 2000 1999 - -------------------------------------------------------------------------------- Net income from continuing operations $ 303.7 $ 250.9 $ 200.9 Total income tax provision (benefit) (10.1) 18.5 87.0 - -------------------------------------------------------------------------------- Income from continuing operations before income taxes $ 293.6 $ 269.4 $ 287.9 - -------------------------------------------------------------------------------- Income taxes on above at federal statutory rate of 35% $ 102.8 $ 94.3 $ 100.8 Increase (Decrease) due to State income tax, net of federal income tax 8.1 7.8 9.2 Amortization of investment tax credits (4.9) (4.9) (5.2) Non-conventional fuels tax credit (102.3) (68.3) (17.2) Permanent reinvestment-foreign income (7.2) (9.3) (1.4) Other (6.6) (1.1) 0.8 - -------------------------------------------------------------------------------- Total income tax provision from continuing operations $ (10.1) $ 18.5 $ 87.0 - -------------------------------------------------------------------------------- Provision for income taxes as a percent of income from continuing operations, before income taxes (3.4%) 6.9% 30.2% - --------------------------------------------------------------------------------
The provision for income taxes as a percent of income from discontinued operations was 37.5% for 1999. There was no income from discontinued operations in 2001 or 2000. The total effective income tax rate differs from the federal statutory rate due to state income tax, net of federal income tax, the non-conventional fuels tax credit and other miscellaneous items. The actual cash paid for income taxes as required by the alternative minimum tax rules in 2001, 2000, and 1999 was $52.4 million, $83.9 million and $62.1 million, respectively.
- -------------------------------------------------------------------------------- I. DISCONTINUED OPERATIONS
TeCom
On Nov. 4, 1999, TECO Energy completed the sale of the assets of TeCom, Inc. for $1.0 million in cash. The company decided to exit the automated energy management systems business because it lacked the distribution channels necessary to effectively reach the markets for its products.
As a result of the company's intention to sell this business, all activities of the subsidiary through Sept. 1, 1999, the measurement date, were reported as discontinued operations on the Consolidated Statements of Income, including amounts from prior years which have been reclassified from continuing operations to discontinued operations. After-tax losses from discontinued operations were $2.5 million for the year ended Dec. 31, 1999. The loss on the sale of the assets of TeCom, including an estimate of activities after the measurement date, was reported as a loss on disposal of discontinued operations. The net after-tax loss from TeCom's disposal of discontinued operations in 1999 was $12.9 million, or 10 cents per share.
Total revenues from discontinued operations related to TeCom were $1.2 million for the year ended Dec. 31, 1999. There were no revenues in 2001 or 2000.
TECO Oil & Gas
On Aug. 28, 1997, the company announced its plan to discontinue operations of its conventional oil and gas subsidiary, TECO Oil & Gas, Inc. Since its formation in 1995, TECO Oil & Gas participated in joint ventures utilizing 3-D seismic imaging in the exploration for oil and gas.
In 1998, TECO Oil & Gas sold its offshore assets for cash and a note receivable (the "Note") to American Resources Offshore, Inc. (ARO) and wrote off the recorded value of all assets associated with the discontinued oil and gas operation, for a net after-tax gain reported from disposal of discontinued operations of $6.1 million.
In March 1999, TECO Oil & Gas sold the Note to a third party for $500,000 in cash, and in a separate transaction ARO agreed to assume disputed joint billing payments of approximately $425,000. A $0.6 million after-tax gain from these transactions was recognized in 1999 as a gain on disposal of discontinued operations.
There were no significant revenues from the discontinued oil and gas operations in 2001, 2000 or 1999.
- -------------------------------------------------------------------------------- J. EARNINGS PER SHARE
In 1997, the Financial Accounting Standards Board issued FAS 128, Earnings per Share, which requires disclosure of basic and diluted earnings per share and a reconciliation (where different) of the numerator and denominator from basic to diluted earnings per share. The reconciliation of basic and diluted earnings per share is shown below:
- ------------------------------------------------------------------------------- Year ended December 31, 2001 2000 1999 - ------------------------------------------------------------------------------- Numerator Net Income from continuing operations, basic $ 303.7 $ 250.9 $ 200.9 Effect of contingent performance shares - (1.9) - - ------------------------------------------------------------------------------- Net Income from continuing operations, diluted $ 303.7 $ 249.0 $ 200.9 ===============================================================================
Net Income, basic $ 303.7 $ 250.9 $ 186.1 Effect of contingent performance shares - (1.9) - - ------------------------------------------------------------------------------- Net Income, diluted $ 303.7 $ 249.0 $ 186.1 ===============================================================================
- ------------------------------------------------------------------------------- Denominator Average number of shares outstanding - basic 134.5 125.9 131.0 Plus: Incremental shares for assumed conversions: Stock options at end of period and contingent performance shares 4.2 3.3 2.3 Less: Treasury shares which could be purchased (3.3) (2.9) (2.1) - ------------------------------------------------------------------------------- Average number of shares outstanding - diluted 135.4 126.3 131.2 ===============================================================================
- ------------------------------------------------------------------------------- Earnings per shares from continuing operations Basic $ 2.26 $ 1.99 $ 1.53 Diluted $ 2.24 $ 1.97 $ 1.53 - ------------------------------------------------------------------------------- Earnings per share Basic $ 2.26 $ 1.99 $ 1.42 Diluted $ 2.24 $ 1.97 $ 1.42 ===============================================================================
- ------------------------------------------------------------------------------- K. SEGMENT INFORMATION
TECO Energy is an electric and gas utility holding company with significant diversified activities. The management of TECO Energy determined its reportable segments based on each subsidiary's contribution of revenues, operating income, net income and total assets. All significant intercompany transactions are eliminated in the consolidated financial statements of TECO Energy but are included in determining reportable segments in accordance with FAS 131, Disclosures about Segments of an Enterprise and Related Information. In November 1999, TECO Energy sold the assets of TeCom, the company's advanced energy management technology subsidiary. Information presented here for 1999 excludes TeCom's results, which are reflected in the consolidated financial statements as discontinued operations.
(1) From continuing operations. (2) Revenues for all periods have been restated to reflect the reclassification of earnings from equity investments from Revenues to Other Income. There was no impact to net income. (3) Beginning in 2001, segment net income is reported on a basis that includes internally allocated financing costs. Prior period net income has been restated to reflect estimated internally allocated financing costs that would have been attributable to such prior periods. Internally allocated costs for 2001, 2000 and 1999 were at pretax rates of 7%, 6.75% and 6.75% respectively, based on the average investment in each subsidiary. (4) Revenues from sales to affiliates were $32.6 million, $32.4 million and $24.8 million in 2001, 2000 and 1999, respectively. (5) Revenues from sales to affiliates were $65.0 million, $67.6 million and $35.5 million in 2001, 2000 and 1999, respectively. (6) Revenues from sales to affiliates were $123.2 million, $118.0 million and $101.0 million in 2001, 2000 and 1999, respectively. (7) Revenues from sales to affiliates were $5.1 million, $4.3 million and $23.1 million in 2001, 2000 and 1999, respectively. (8) Revenues from sales to affiliates were $23.7 million, $6.5 million and $0.6 million in 2001, 2000 and 1999, respectively. (9) Total assets include investments in unconsolidated affiliates of $120.4 million, $145.5 million and $103.3 million at Dec. 31, 2001, 2000 and 1999, respectively. Total assets also includes $286.4 million and $383.1 million in other non-current equity investments at Dec. 31, 2001 and 2000, respectively. (10) Total assets include $129.4 million, $65.7 million and $40.9 million in goodwill net of amortization at Dec. 31, 2001, 2000 and 1999, respectively. (11) Total assets include $52.5 million and $50.4 million in investments in unconsolidated affiliates at Dec. 31, 2001 and 2000, respectively. (12) Total assets include $36.4 million, $27.4 million and $1.9 million in goodwill net of amortization at Dec. 31, 2001, 2000 and 1999, respectively. (13) Revenues shown for 1999 exclude a $7.9 million credit resulting from a charge. See Note L. (14) Revenues shown for 1999 are after the revenue deferral of $11.9 million. (15) Revenues include a pretax benefit of $7.9 million in 1999. See Note L. (16) Net income excludes after-tax charges totaling $13.7 million in 1999. See Note L. (17) Net income includes after-tax charges totaling $19.6 million in 1999, which included $13.7 million of charges recorded at Tampa Electric. See Note L.
Tampa Electric Company provides retail electric utility services to almost 584,000 customers in West Central Florida. Its Peoples Gas System division is engaged in the purchase, distribution and marketing of natural gas for more than 272,000 residential, commercial, industrial and electric power generation customers in the state of Florida. TECO Transport Corporation, through its wholly owned subsidiaries, transports, stores and transfers coal and other dry bulk commodities for third parties and Tampa Electric. TECO Transport's subsidiaries operate on the Mississippi, Ohio and Illinois rivers, in the Gulf of Mexico and worldwide. TECO Coal Corporation, through its wholly owned subsidiaries, owns mineral rights, and owns or operates surface and underground mines and coal processing and loading facilities in Kentucky, Tennessee and Virginia. In 2000, these subsidiaries began operating synthetic fuel processing facilities, whose production qualifies for the non-conventional fuels tax credit. TECO Coal's subsidiaries sell their coal production to third parties. TECO Power Services Corporation (TPS) has subsidiaries that have interests in independent power projects in Florida, Virginia, Texas, Arkansas, Mississippi, Arizona, Hawaii and Guatemala, and transmission and distribution facilities in Guatemala. TPS also has investments in unconsolidated affiliates that participate in independent power projects in other parts of the U.S. and the world. TECO Energy's other diversified businesses are engaged in natural gas production from coalbeds, the marketing of natural gas, and energy services and engineering. Also included is the company's investment in the propane business.
Foreign Operations TPS has independent power operations and investments in Guatemala. TPS, through its subsidiaries, has a 96 percent ownership interest and operates a 78-megawatt power station that supplies energy to Empresa Electrica de Guatemala, S.A. (EEGSA), an electric utility in Guatemala, under a U.S. dollar-denominated power sales agreement. At Dec. 31, 2001, TPS, through a wholly owned subsidiary, had a 100 percent ownership interest in a 120-megawatt power station and in transmission facilities in Guatemala. The plant provides capacity under a U.S. dollar- denominated power sales agreement to EEGSA. TPS, through a subsidiary, owns a 30 percent interest in a consortium that includes Iberdrola, an electric utility in Spain, and Electricidade de Portugal, an electric utility in Portugal. The consortium owns an 80.9 percent interest in EEGSA. Total assets at Dec. 31, 2001, 2000 and 1999 included $454.2 million, $442.6 million and $379.4 million, respectively, related to these Guatemalan operations and investments. Revenues included $79.9 million, $69.0 million and $19.5 million for the years ended Dec. 31, 2001, 2000 and 1999, respectively, and operating income included $38.0 million, $23.7 million and $10.1 million for the years ended Dec. 31, 2001, 2000 and 1999, respectively, from these Guatemalan operations and investments.
________________________________________________________________________________ L. OTHER NON-OPERATING ITEMS AFFECTING NET INCOME
In the first quarter of 2001, TECO Energy recorded $7.2 million of after-tax charges ($11.1 million pretax) to adjust asset valuations. The adjustments included a $6.1 million after-tax adjustment ($9.3 million pretax) related to the sale of TPS' minority interests in Energia Global International, Ltd. (EGI) which owned smaller power generation projects in Central America, and a $1.1 million after-tax adjustment ($1.8 million pretax) to adjust the carrying value of leveraged leases at TECO Investments.
In 2000, TECO Energy's results included an $8.3-million, after-tax gain from the US Propane and Heritage Propane transactions offset by after-tax charges of $5.2 million to adjust the value of leveraged leases and $3.8 million to adjust property values at TECO Properties. Because of the offsetting nature of these items, there was no significant effect on earnings in 2000.
In 1999, TECO Energy's results included charges totaling $21.1 million pretax ($19.6 million after tax) and consisted of the following: Tampa Electric recorded a charge of $10.5 million ($6.4 million after tax) based on FPSC audits of its 1997 and 1998 earnings, which among other things, limited its equity ratio to 58.7 percent, a decrease of 91 basis points and 224 basis points from 1997's and 1998's ratios, respectively. Tampa Electric also recorded a charge of $3.5 million after tax, representing management's estimate of additional expense to resolve the litigation filed by the United States Environmental Protection Agency, which was then pending. After-tax charges totaling $6.1 million were also recognized reflecting corporate income tax provisions and settlements related to prior years' tax returns. These charges were recorded at Tampa Electric (a $3.8-million net after-tax charge, after recovery under the then current regulatory agreement), at TECO Investments (a $4.3-million after-tax charge) and at the TECO Energy corporate level (a $2.0-million after-tax benefit). A charge of $6.0 million ($3.6 million after tax) was recorded to adjust the carrying value of certain investments in leveraged aircraft leases to reflect lower anticipated residual values.
________________________________________________________________________________ M. COMMITMENTS AND CONTINGENCIES TECO Energy has made certain commitments in connection with its continuing capital improvements program. At Dec. 31, 2002, these commitments totaled approximately $1.6 billion, with $1.2 billion related to 2002 and $0.4 billion related to the 2003 - 2006 period. TECO Energy estimates that net capital investments for ongoing businesses will be about $1.2 billion in 2002, $764 million in 2003 and approximately $862 million for the years 2004 through 2006, as summarized below.
- -------------------------------------------------------------------------------- FORECASTED-CAPITAL INVESTMENTS - -------------------------------------------------------------------------------- (millions) 2002 2003 2004 - 2006 Total 2002-2006 - -------------------------------------------------------------------------------- Florida Operations $ 603 $ 359 $761 $1,723 Independent Power 514 352 -- 866 Transportation 20 24 55 99 Other 46 29 46 121 - -------------------------------------------------------------------------------- $1,183 $ 764 $862 $2,809 ================================================================================
For 2002, Tampa Electric expects to spend $541 million, consisting of $330 million for the repowering project at the Gannon Station, $16 million in construction costs on Polk Unit 3 and $195 million to support system growth and generation reliability. Tampa Electric's estimated capital expenditures over the 2003-2006 period are projected to be $878 million, including $131 for the Gannon repowering project. At the end of 2001, Tampa Electric had outstanding commitments of about $453 million for the Gannon repowering project and Polk Unit 3. Capital expenditures for Peoples Gas System are expected to be about $62 million in 2002 and $242 million during the 2003-2006 period. Included in these amounts are approximately $42 million annually for projects associated with customer growth and system expansion. The remainder represents capital expenditures for ongoing maintenance and system safety.
TPS expects to invest $514 million in 2002, which is net of $500 million of non-recourse project financing expected for the Dell, McAdams, Frontera and Commonwealth Chesapeake power stations, and $352 million in 2003, mainly for the completion of the Gila River, Union, Dell and McAdams power stations. At the end of 2001, TPS had outstanding commitments of about $1.1 billion on these projects. Estimates for TPS include net contributions to projects of unconsolidated affiliates and other investments of $984 million. These amounts, consisting primarily of the net investments in the Union and Gila River power stations, are estimated at $664 million in 2002 and $320 million in 2003. The 2002 amounts are net of $460 million of non-recourse project construction financing for the Union and Gila River power stations, and include $125 million of TPS equity investment upon completion of the first phase of the Union Power Station. The other unregulated companies expect to invest $66 million in 2002 and $154 million during 2003 through 2006, mainly for normal renewal and replacement capital. Tampa Electric Company is a potentially responsible party for certain superfund sites and, through its Peoples Gas System division, for certain superfund and 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 $22 million over the next 10 years. The environmental remediation costs associated with these sites have been recorded on the accompanying consolidated balance sheet and are not expected to have a significant impact on customer prices. TECO Energy has commitments under long-term operating leases, primarily for building space, office equipment and heavy equipment, three ocean-going barges and one ocean-going tug boat at TECO Transport, and certain equipment at TPS' Hardee Power Station. On Dec. 21, 2001, TECO Transport sold three ocean-going barges and one ocean-going tug boat in a sales-leaseback transaction to be accounted for as an operating lease. The lease term is 12 years with an early buyout option in January 2007. TPS completed a transaction on Dec. 29, 2000, where certain equipment at its Hardee Power Station was sold to a third party and leased back under a 12-year operating lease. Total rental expense for these operating leases, included in the Consolidated Statements of Income for the years ended Dec. 31, 2001, 2000 and 1999 was $20.4 million, $17.6 million and $12.8 million, respectively. The following is a schedule of future minimum lease payments at Dec. 31, 2001 for all operating leases with noncancelable lease terms in excess of one year:
- -------------------------------------------------------------------------------- Year ended Dec. 31: Amount (millions) - -------------------------------------------------------------------------------- 2002 $ 12.0 2003 15.3 2004 15.6 2005 15.0 2006 14.9 Later Years 83.3 - -------------------------------------------------------------------------------- Total minimum lease payments $156.1 ================================================================================
The company has outstanding letters of credit of $22.4 million at Dec. 31, 2001, which guarantee performance to third parties related to debt service, major maintenance requirements and various trade activities. The company also has financial guarantees of $265.1 million at Dec. 31, 2001, primarily for construction related debt for projects in which TPS is a participant. In addition, TECO Energy has guaranteed a $500 million equity bridge loan of the unconsolidated TECO/Panda Affiliate for the construction of the Gila River and Union power stations. The TPS equity bridge financing includes two financial covenants, debt to capital and interest coverage requirements on a TECO Energy consolidated basis. The debt to capital as defined in the agreements must not exceed 65 percent at the end of each quarter and interest coverage as defined must equal or exceed 3.0 times for the twelve-month period ended each quarter. At Dec. 31, 2001 debt to capital was 62.1 percent and interest coverage was 4.3 times. In addition, this financing requires that TECO Energy maintain senior unsecured credit ratings better or equal to one rating of BBB and one rating of BBB-. Failure to meet these covenants would constitute a default event and the financing would become due and payable.
- -------------------------------------------------------------------------------- N. MERGERS, ACQUISITIONS AND DISPOSITIONS In November 2001, TECO Solutions acquired Prior Energy Corporation, a leading natural gas management company serving customers in Alabama, Florida, Georgia, Louisiana, Mississippi, North Carolina, South Carolina, Tennessee and Texas. Prior Energy handles all facets of natural gas energy management services, including natural gas purchasing and marketing. The company has an established market base in the Southeast and one of the top customer service reputations in the region. The acquisition was accounted for by the purchase method of accounting and, accordingly, the results of operations of Prior Energy are included as part of TECO Solutions' results beginning Nov. 1, 2001. The total cost of the acquisition was $23.0 million, plus a net working capital payment of $6.0 million. Goodwill of $8.2 million was recorded, representing the excess of purchase price over the fair market value of assets acquired. Under FAS 141, effective for all business combinations initiated after June 30, 2001, goodwill is no longer subject to amortization. Net intangible assets of $40.8 million were recorded, representing the value of customer backlog and supply agreements as well as the open cash flow hedges as of Nov. 1, 2001, which are being amortized over 2001 through 2004. The purchase price allocation is subject to revision in 2002, based on the final determination of appraised and other fair values. A summary of the estimated assets acquired and liabilities assumed is summarized below:
- -------------------------------------------------------------------------------- millions - -------------------------------------------------------------------------------- Other current assets $ 45.9 Property, plant and equipment 0.1 Goodwill 8.2 Intangible assets 40.8 Long-term derivative assets 1.4 Current derivative liabilities (29.8) Other current liabilities (35.1) Long-term derivative liability (2.5) - -------------------------------------------------------------------------------- Net assets acquired $ 29.0 - --------------------------------------------------------------------------------
In March 2001, TPS acquired the Frontera Power Station located near McAllen, Texas, accounting for the transaction using the purchase method of accounting. This 477-megawatt, natural gas-fired combined-cycle plant, originally developed by CSW Energy (CSW), began commercial operation in May 2000. As a condition of the merger of Central & South West Corporation, CSW's parent company, with American Electric Power Company, Inc., the FERC required CSW to divest its ownership in this facility. The total cost of the acquisition was $265.3 million. Goodwill of $70.4 million, representing the excess of purchase price over the fair market value of assets acquired, was recorded, and was amortized on a straight-line basis over 40 years until the requirements of FAS 141 became effective on Jan. 1, 2002 (See Note A). The results of operations of Frontera Power Station are included as part of TPS' results beginning March 16, 2001.
A summary of the assets acquired and liabilities assumed is summarized below:
- -------------------------------------------------------------------------------- millions - -------------------------------------------------------------------------------- Current assets $ 6.0 Property, plant and equipment 180.9 Goodwill 70.4 Other assets 8.7 Current liabilities (0.7) - -------------------------------------------------------------------------------- Net assets acquired $265.3 ================================================================================
The following pro forma disclosures include Prior Energy and the Frontera Power Station as if they had been included in TECO Energy's financial statements for the years ended Dec. 31, 2001 and 2000, and include Prior Energy for the year ended Dec. 31, 1999.
- -------------------------------------------------------------------------------- Pro forma, year ended Dec. 31, 2001 2000 1999 - -------------------------------------------------------------------------------- Revenues (millions) $ 3,250.3 $ 2,856.2 $ 2,163.9 Net income (millions) $ 300.3 $ 253.9 $ 201.6 Earnings per share - basic $ 2.23 $ 2.02 $ 1.54 - --------------------------------------------------------------------------------
This pro forma information is not necessarily indicative of the operating results that would have occurred had the acquisitions been completed as of the dates indicated, nor are they indicative of future operating results.
In October 2001, TECO BGA, a unit of TECO Solutions, purchased a district cooling business from FPL Energy Services, a subsidiary of FPL Group. The acquisition includes a 12,000-ton design capacity cooling plant located in downtown Miami. This acquisition provides TECO BGA with a stronger presence in the growing South Florida energy market, long-term contract business, a franchise agreement with the city of Miami and the potential for expansion. The acquisition was accounted for by the purchase method of accounting and, accordingly, its results of operations are included as part of TECO BGA's results beginning Oct. 25, 2001. The total cost of the acquisition was $12.5 million. No goodwill was recorded for the acquisition. The acquisition was not material to the financial statements; no pro forma disclosures are presented. On Nov. 1, 2000, TECO Coal acquired all of the outstanding stock of Perry County Coal for $14.9 million, comprised of $12.1 million in cash and $2.8 million in notes. Perry County Coal owns or controls more than 23 million tons of low-sulfur reserves, and operates both deep and surface contract mines. The acquisition was accounted for by the purchase method of accounting and, accordingly, the results of operations and assets of Perry County Coal are included as part of TECO Coal's results beginning Nov. 1, 2000. In September 2000, TECO Energy acquired BCH Mechanical, Inc. and its affiliated companies ("BCH") accounting for the transaction using the purchase method of accounting. BCH is one of the leading mechanical contracting firms in Florida. TECO Energy purchased a combination of stock and assets of the BCH companies for $34.8 million, comprised of $26.1 million in cash, $2.9 million in notes, and 233,819 shares of TECO Energy common stock. Goodwill of $25.9 million representing the excess of purchase price over the fair market value of assets acquired was recorded, and was amortized on a straight-line basis over 20 years, until the requirements of FAS 141 became effective on Jan. 1, 2002 (See Note A). The result of operations of BCH are included as part of TECO Energy's results beginning Sept. 1, 2000. BCH is included within the Other diversified businesses segment. In connection with this transaction, TECO Solutions was formed to support TECO Energy's strategy of offering customers a comprehensive and competitive package of energy services and products. Operating companies under TECO Solutions include TECO BGA (formerly Bosek, Gibson and Associates), BCH, TECO Partners, TECO Propane Ventures, TECO Gas Services, Prior Energy and TECO Properties. In February 2000, TECO Energy entered into an agreement to form US Propane, a joint venture to combine its Peoples Gas Company (PGC) propane operations with the propane operations of Atmos Energy Corporation, AGL Resources Inc. and Piedmont Natural Gas Company, Inc. In June 2000, US Propane announced that it would combine its propane operations with those of Heritage Propane Partners, L.P. to create the fourth largest retail propane distributor in the United States that will distribute propane to over 480,000 customers in 28 states. Through a series of transactions completed Aug. 10, 2000, US Propane sold its propane business to Heritage Propane Partners for approximately $180 million in cash and other consideration, and purchased all of the outstanding common stock of Heritage Holdings, Inc., the general partner of Heritage Propane Partners, for $120 million. US Propane now owns the general partner interest and 34 percent of the limited partnership interests of Heritage Propane Partners. TECO Energy through its wholly-owned subsidiary TECO Propane Ventures, LLC (TPV), is accounting for its $40.8 million investment, or approximate 38 percent interest in US Propane under the equity method of accounting. As a result of these transactions, TPV also received $19.3 million in cash and recognized a pretax gain of $13.6 million ($8.3 million after-tax) on the sale of PGC assets and liabilities to the extent acquired by US Propane and Heritage Propane Partners.
- -------------------------------------------------------------------------------- O. SUBSEQUENT EVENTS On January 23, 2002, TECO Energy sold 17.965 million units of mandatorily convertible securities in the form of 9.5% mandatorily convertible equity units at $25 per unit. Each security unit consisted of $25 in principal amount of a trust preferred security of TECO Capital Trust II, a Delaware business trust formed by TECO Energy, with a stated liquidation amount of $25 and a contract to purchase shares of common stock of TECO Energy in January 2005 at a price per share of between $26.29 and $30.10 based on the market price at the time. The equity units represent an indirect interest in a corresponding amount of TECO Energy subordinated debt. The $436 million net proceeds from the offering were used to repay short-term debt and for general corporate purposes. As part of its $1 billion line of credit facility, TECO Energy has the capacity to issue up to $250 million in letters of credit with a syndicate of banks. In January and February 2002, TECO Energy issued $141.7 million in letters of credit under this facility, primarily related to construction support for the Gila River and Union power stations. On February 7, 2002, TPS entered into an agreement for TPS to purchase and for Panda Energy International Inc. (Panda) to sell its interest in TECO-Panda Generating Company L.P., the joint venture formed to build, own and operate the Gila River and Union power stations, in 2007 for up to $60 million. Panda has the right to cancel the transaction for $20 million. The purchase agreement can be triggered earlier under certain default conditions under a bank loan made to Panda using the purchase agreement as collateral.
- -------------------------------------------------------------------------------- P. QUARTERLY DATA (unaudited) Financial data by quarter is as follows: (unaudited)
(1) Millions. (2) Dividend paid on TECO Energy common stock. (3) Trading prices for common shares.
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
During the period Jan. 1, 2000 to the date of this report, TECO Energy 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 III
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
(a) The information required by Item 10 with respect to the directors of the registrant is included under the caption "Election of Directors" on pages 2 through 3 of TECO Energy's definitive proxy statement, dated March 4, 2002, for its Annual Meeting of Shareholders to be held on April 17, 2002 (Proxy Statement) and is incorporated herein by reference.
(b) The information required by Item 10 concerning executive officers of the registrant is included under the caption "Executive Officers of the Registrant" on page 16 of this report.
(C) The information required by Item 10 concerning Section 16(a) Beneficial Ownership Reporting Compliance is included under that caption on page 14 of the Proxy Statement and is incorporated herein by reference.
Item 11.
Item 11. EXECUTIVE COMPENSATION.
The information required by Item 11 is included in the Proxy Statement beginning on page 6 and ending on page 13, and under the caption "Compensation of Directors" on page 4, and is incorporated herein by reference.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information required by Item 12 is included under the caption "Share Ownership" on pages 4 and 5 of the Proxy Statement and is incorporated herein by reference.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information required by Item 13 is included under the caption "Election of Directors" on page 1 of the Proxy Statement and is incorporated herein by reference.
PART IV
Item 14.
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) 1. Financial Statements - See index on page 40 2. Financial Statement Schedules - See index on page 40 3. Exhibits - See index beginning on page 73
(b) Reports on Form 8-K
The registrant filed the following reports on Form 8-K during the last quarter of 2001.
The registrant filed a Current Report on Form 8-K dated Oct. 9, 2001 under "Item 5. Other Events" and "Item 7. Financial Statements, Pro ------------ ------------------------- Forma Financial Statements and Exhibits", furnishing certain exhibits --------------------------------------- for incorporation by reference into the Registration Statement on Form S-3 previously filed with the Securities and Exchange Commission (File No. 333-61758).
The registrant filed a Current Report on Form 8-K dated Dec. 7, 2001 under "Item 5. Other Events", reporting TECO Energy's exposure ------------ relating to Enron Corp.
The registrant filed the following reports on Form 8-K subsequent to Dec. 31, 2001.
The registrant filed a Current Report on Form 8-K dated Jan. 9, 2002, under "Item 5. Other Events" reporting on TECO Energy's 2001 ------------ financial results and providing updated information on the Company's 2002 outlook, its capital spending plans and reporting on the status of bank financing for the construction of two power plants for TECO Power Services.
The registrant filed a Current Report on Form 8-K dated Jan. 9, 2002, under "Item 5. Other Events" and "Item 7. Financial Statements, Pro ------------ ------------------------- Forma Financial Statements and Exhibits", furnishing certain exhibits --------------------------------------- for incorporation by reference into the Registration Statement on Form S-3 previously filed with the Securities and Exchange Commission (File No. 333-61758).
The registrant filed a Current Report on Form 8-K dated Jan. 15, 2002, under "Item 5. Other Events" and "Item 7. Financial Statements, Pro ------------ ------------------------- Forma Financial Statements and Exhibits", furnishing certain exhibits --------------------------------------- for incorporation by reference into the Registration Statement on Form S-3 previously filed with the Securities and Exchange Commission (File No. 333-61758).
The registrant filed a Current Report on Form 8-K dated Jan. 15, 2002, under "Item 5. Other Events" and "Item 7. Financial Statements, Pro ------------ ------------------------- Forma Financial Statements and Exhibits", furnishing certain exhibits --------------------------------------- for incorporation by reference into the Registration Statement on Form S-3 previously filed with the Securities and Exchange Commission (File No. 333-61758).
The registrant filed a Current Report on Form 8-K dated Jan. 24, 2002, under "Item 5. Other Events" reporting that Moody's Investors Service ------------ announced that it had changed the outlooks of the long-term ratings of TECO Energy, Inc. and Tampa Electric Company to negative.
(c) The exhibits filed as part of this Form 10-K are listed on the Exhibit Index immediately preceding such Exhibits. The Exhibit Index is incorporated herein by reference.
Schedule II
TECO Energy, Inc.
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES For the Years ended Dec. 31, 2001, 2000 and 1999 (millions)
- ----------------------------- (1) Write-off of individual bad debt accounts (2) Includes $0.2 million and $0.3 million in 2000 and 1999, respectively, for TeCom Discontinued Operations.
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 28th day of March, 2002.
TECO ENERGY, INC.
By R. D. FAGAN* ----------------------------------- R. D. FAGAN, Chairman of the Board, President 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 28, 2002:
Signature Title --------- -----
R. D. FAGAN* Chairman of the Board, President, ------------------------ Director and Chief Executive Officer R. D. FAGAN (Principal Executive Officer)
/s/ G. L. GILLETTE Senior Vice President-Finance ----------------------- and Chief Financial Officer G. L. GILLETTE (Principal Financial Officer)
S. A. MYERS* Vice President-Corporate Accounting and Tax ----------------------- (Principal Accounting Officer) S. A. MYERS
Signature Title Signature Title --------- ----- --------- -----
C. D. AUSLEY* Director W. D. ROCKFORD* Director -------------------- ----------------- C. D. AUSLEY W. D. ROCKFORD
S. L. BALDWIN* Director W. P. SOVEY* Director -------------------- ----------------- S. L. BALDWIN W. P. SOVEY
J. L. FERMAN, JR.* Director J. T. TOUCHTON* Director -------------------- ----------------- J. L. FERMAN, JR. J. T. TOUCHTON
L. GUINOT, JR.* Director J. A. URQUHART* Director -------------------- ----------------- L. GUINOT, JR. J. A. URQUHART
I. D. HALL* Director J. O. WELCH, JR.* Director -------------------- ----------------- I.D. HALL J. O. WELCH, JR.
T. L. RANKIN* Director -------------------- T. L. RANKIN
*By: /s/ G. L. GILLETTE -------------------------------- G. L. GILLETTE, Attorney-in-fact
INDEX TO EXHIBITS
_____________ * Indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. Exhibits filed with periodic reports of TECO Energy, Inc. were filed under Commission File No. 1-8180.
Certain instruments defining the rights of holders of long-term debt of TECO Energy, Inc. and its consolidated subsidiaries authorizing in each case a total amount of securities not exceeding 10 percent of total assets on a consolidated basis are not filed herewith. TECO Energy, Inc. will furnish copies of such instruments to the Securities and Exchange Commission upon request.
Executive Compensation Plans and Arrangements
Exhibits 10.1 through 10.5 and 10.7 through 10.26 above are management contracts or compensatory plans or arrangements in which executive officers or directors of TECO Energy, Inc. participate.