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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

OR

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

YES    x         NO    ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendments to this Form 10-K.    ¨

Indicate by check mark whether TECO Energy, Inc. is an accelerated filer (as defined in Exchange Act Rule 12b-2).

YES    x         NO    ¨

Indicate by check mark whether Tampa Electric Company is an accelerated filer (as defined in Exchange Act Rule 12b-2).

YES    x         NO    ¨

The aggregate market value of TECO Energy, Inc.’s common stock held by nonaffiliates of the registrant as of June 28, 2002 was $3,862,495,376.

The aggregate market value of Tampa Electric Company’s common stock held by nonaffiliates of the registrant as of June 28, 2002 was zero.

The number of shares of TECO Energy, Inc.’s common stock outstanding as of February 28, 2003 was 176,049,947.

As of February 28, 2003, there were 10 shares of Tampa Electric Company’s common stock issued and outstanding, all of which were held, beneficially and of record, by TECO Energy, Inc.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Definitive Proxy Statement relating to the 2003 Annual Meeting of Shareholders of TECO Energy, Inc. are incorporated by reference into Part III.

Tampa Electric Company meets the conditions set forth in General Instruction (I) (1) (a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format.

This combined Form 10-K represents separate filings by TECO Energy, Inc. and Tampa Electric Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Tampa Electric Company makes no representations as to the information relating to TECO Energy, Inc.’s other operations.

Page 1 of 143

Index to Exhibits appears on page 139

PART I

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 and its subsidiaries had 6,319 employees as of Dec. 31, 2002.

TECO Energy makes its SEC filings (Form 10-K, 10-Q and 8-K, and any amendments to those reports) and other information available free of charge on its web site as soon as reasonably practical after it has been electronically filed with the SEC. This information is available at the Investor Relations page of TECO Energy’s web site at www.tecoenergy.com.

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 operates regulated utility companies and other unregulated businesses. 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 597,000 customers in West Central Florida with a net system generating capability of 3,784 megawatts (MW). Peoples Gas System (PGS), a division of Tampa Electric Company, is engaged in the purchase, distribution and marketing of natural gas for residential, commercial, industrial and electric power generation customers in Florida. With more than 281,000 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 2002 was 1.3 billion therms.

TECO Transport Corporation, 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, 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 eastern Kentucky, Tennessee and southwestern Virginia.

TECO Power Services Corporation (TPS), 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 Guatemala.

TECO Energy’s other unregulated companies include TECO Energy Services, Inc. (formerly TECO BGA, Inc. and BCH Mechanical, Inc. and its affiliated companies), TECO Gas Services, Inc., TECO Properties Corporation, Prior Energy Corporation, TECO Propane Ventures, LLC (TPV), TECO Partners, Inc. and TECO Investments, Inc. Except for TECO Investments, these operating companies are organized under TECO Solutions, Inc., a Florida corporation. The TECO Solutions’ subsidiaries provide engineering and energy services to customers primarily in Florida; 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.

Revenues for TECO Energy’s significant business segments follow for the years indicated. For additional financial information regarding TECO Energy’s significant business segments, see Notes to the Consolidated Financial Statements—Note Q, Segment Information.

Revenues from Continuing Operations

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TECO Coalbed Methane, Inc., an Alabama corporation, had developed jointly with another entity the natural gas potential of Alabama’s Black Warrior Basin. In December 2002, TECO Energy sold substantially all of its coalbed methane assets to the Municipal Gas Authority of Georgia. TECO Coalbed Methane’s results are accounted for as discontinued operations for all periods reported. Revenues from the discontinued operations of TECO Coalbed Methane were $39.7 million, $55.0 million and $43.0 million for the years ended Dec. 31, 2002, 2001 and 2000, respectively.

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 2,700 employees as of Dec. 31, 2002, of which 936 were represented by the International Brotherhood of Electrical Workers and 288 were represented by the Office and Professional Employees International Union.

In 2002, approximately 48 percent of Tampa Electric’s total operating revenue was derived from residential sales, 29 percent from commercial sales, 10 percent from industrial sales and 13 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:

Operating Revenue

Megawatt-hour Sales

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 and represents less than 3 percent of Tampa Electric’s 2002 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.

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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 Regulation—Tampa Electric Rate Stabilization Strategy section of Management’s Discussion & Analysis of Financial Condition & Results of Operations (MD&A).

Since the expiration of the agreements noted above, Tampa Electric is not under a new stipulation. Therefore, its rates and allowed return on equity (ROE) range of 10.75 percent to 12.75 percent with a midpoint of 11.75 percent are 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.

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.

In September 2002, Tampa Electric filed with the FPSC for approval of fuel and purchased power, capacity, environmental and conservation cost recovery rates for the period January through December 2003. In November, the FPSC approved Tampa Electric’s requested changes. In February 2003, Tampa Electric filed to revise the fuel cost recovery rates for the period April through December 2003 due to higher projected fuel prices. In March 2003, the FPSC approved Tampa Electric’s revised rates. See Regulation—Cost Recovery Clauses section of MD&A.

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 the Regulation—Federal Energy Regulatory Commission (FERC) Restructuring Initiatives and Transmission Rates sections of MD&A.

Federal, state and local environmental laws and regulations cover air quality, water quality, land use, power plant, substation and transmission line siting, noise and aesthetics, solid waste and other environmental matters. See Environmental Matters on pages 6 through 8.

TECO Transport sells transportation services, and TECO Power Services sells generating capacity and energy, to Tampa Electric and 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 the Regulation—Utility Competition: Electric section of MD&A. 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 TECO Power Services on pages 11 and 12.

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 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 in the state 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.

FERC requires transmission system owners to operate an Open Access Non-discriminatory Transmission, Standard Costs, Same-time Information System (OASIS) 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. This rule works to open access for wholesale power flows on transmission systems and requires utilities such as Tampa Electric, which own transmission facilities, to provide services to wholesale transmission

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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. To facilitate compliance, owners must maintain Standards of Conduct to ensure that personnel involved in marketing wholesale power are functionally separated from personnel involved in transmission services and reliability functions. Tampa Electric, together with other utilities, has an OASIS system and believes it is in compliance with the Standards of Conduct. See Regulation - Transmission Rates section of MD&A.

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 and December 2000, Tampa Electric and two of the other IOUs operating in Florida agreed to form an RTO, 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 Tampa Electric’s and the other two 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, compliance version of GridFlorida reflecting the FPSC’s views in the December 2001 order, which was filed with the FPSC in late March 2002. After reviewing the compliance filing, the FPSC issued another order in September 2002 approving in part and setting for further hearing the remaining issues. In October 2002, the State of Florida Office of Public Counsel filed an appeal of the FPSC orders to the Florida Supreme Court. The case is still pending. Tampa Electric continues to take an active role in monitoring and influencing the development of GridFlorida as well as other possible RTOs in the southeast region.

In July 2002, FERC issued a Notice of Proposed Rulemaking on “Standard Market Design” which seeks to develop new rules to remedy remaining undue discrimination in transmission and other industry practices, establish standard market design rules to encourage and facilitate wholesale competition and resolve pending issues related to RTOs and other matters. While that rulemaking has yet to be completed, it has elicited substantial negative reaction from several regions, states, parts of the industry and members of Congress. If enacted as proposed, it would increase competition for generation in the wholesale markets. While FERC indicated it intended to have a final rule in place by 2003, the schedule has been delayed and a new date has not been set.

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. No action was taken in the 2002 legislative session with regard to those recommendations. It is unclear at this time when or if any legislation regarding those recommendations will be proposed in future legislative sessions or, if proposed, the likelihood of it being passed.

Fuel

Approximately 95 percent of Tampa Electric’s generation of electricity for 2002 was coal-fired, with oil representing approximately 2 percent and natural gas representing approximately 3 percent. Tampa Electric used its generating units to meet approximately 83 percent of the system load requirements with the remaining 17 percent coming from purchased power. A lower level of coal generation as a percentage of total generation is anticipated for 2003 as a result of Gannon’s repowering to Bayside Power Station.

Tampa Electric’s average delivered fuel cost per million Btu and average delivered cost per ton of coal burned have been as follows:

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Tampa Electric’s generating stations burn fuels as follows: Gannon Station burns low-sulfur coal and No. 2 fuel oil; 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 and No. 2 fuel oil; Polk Power Station burns high-sulfur coal, which is gasified and subjected to sulfur and particulate matter 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 7.1 million tons of coal during 2002 and estimates that its coal consumption will be about 6.7 million tons for 2003. During 2002, Tampa Electric purchased approximately 58 percent of its coal under long-term contracts with five suppliers, and approximately 42 percent of its coal in the spot market. Tampa Electric expects to obtain approximately 74 percent of its coal requirements in 2003 under long-term contracts with six suppliers and the remaining 26 percent in the spot market. This temporary change in the balance of long-term versus spot contracts is due to declining spot coal needs at Gannon Station in connection with the repowering to Bayside Power Station. Tampa Electric’s remaining long-term 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 the TECO Transport section on page 13 and the TECO Coal section on pages 13 and 14.

In 2002, approximately 59 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 has supply agreements through Dec. 31, 2003 for No. 2 fuel oil for its Polk, Gannon and Big Bend Stations at prices based on Gulf Coast Cargo spot indices. No. 6 fuel oil is purchased on the spot market for its Phillips Stations.

Natural Gas. In early 2003, Tampa Electric will complete its contracts for 60 percent of its expected gas needs for the 2003 summer period. The remaining 40 percent will be procured on the short-term spot market. Tampa Electric has long-term firm transportation capacity in place for its expected needs.

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 November 2005 to March 2021.

Franchise fees payable by Tampa Electric, which totaled $27.3 million in 2002, are calculated using a formula based primarily on electric revenues and are collected on customers’ bills.

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 2023, respectively.

Environmental Matters

Consent Decree

Tampa Electric Company, in cooperation with the Environmental Protection Agency (EPA) and the U.S. Department of Justice, signed a Consent Decree which became effective October 5, 2000, and a Consent Final Judgment with the Florida Department of Environmental Protection (FDEP), effective December 7, 1999. Pursuant to these agreements, allegations of violations of New Source Review requirements of the Clean Air Act were resolved, provision was made for environmental controls and pollution reductions, and Tampa Electric began implementing a comprehensive program that will dramatically decrease emissions from the company’s power plants.

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The emission reduction requirements included specific detail with respect to the availability of flue gas desulfurization systems (scrubbers) to help reduce sulfur dioxide (SO2), projects for nitrogen oxide (NOx) reduction efforts on Big Bend Units 1 through 4, and the repowering of the coal-fired Gannon Station to natural gas. 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. Tampa Electric anticipates commercial operation for the first repowered Bayside unit by May 1, 2003. The repowering of the second unit is scheduled for completion by May 1, 2004. By May 1, 2005, Tampa Electric must decide whether to install NOx controls, repower, or shutdown Big Bend Unit 4, and it must implement the chosen methodology by June 1, 2007. By May 1, 2007, Tampa Electric will decide whether to install NOx controls, repower, or shutdown Big Bend Units 1, 2 and 3 and it must implement the chosen methodology beginning in 2008. Tampa Electric’s capital investment forecast includes amounts in the 2006 and 2007 period for compliance with the NOx reduction requirements.

Emission Reductions

Since 1998, Tampa Electric has reduced annual SO2, NOx, and particulate matter (PM) emissions from its facilities by 105,418 tons, 11,206 tons, and 1,113 tons, respectively.

Reductions in SO2 emissions were primarily accomplished through the installation of scrubber systems on Big Bend Units 1 and 2. Big Bend Unit 4 was originally constructed with a scrubber. The Big Bend Unit 4 scrubber system was modified in 1994 to allow it to scrub emissions from Big Bend Unit 3. Currently, the scrubbers at Big Bend Station remove more than 95 percent of the SO2 emissions from the flue gas streams. In addition, reductions in NOx have been accomplished through combustion tuning and optimization projects at Big Bend and Gannon Stations.

Particulate matter (PM) is controlled at Big Bend and Gannon Stations through the use of electrostatic precipitators, which remove more than 99.9 percent of the PM generated during the combustion process.

Significant reductions in emissions outlined in the consent decree and consent final judgment will result from the ongoing repowering of the Gannon to Bayside Power Station and, should Tampa Electric decide to continue to burn coal, the installation of additional NOx emissions controls on all Big Bend Units. By 2010, these projects will result in the additional phased reduction of SO2 by 47,467 tons per year, NOx by 50,488 tons per year, and PM by 1,981 tons per year. In total, Tampa Electric’s emission reduction initiatives will result in the reduction of SO2, NOx, and PM emissions by 87 percent, 89 percent, and 60 percent, respectively, below 1998 levels. With these improvements in place, Tampa Electric’s facilities will meet the same standards required of new power generating facilities and help to significantly enhance the quality of the air in the community.

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 PM emissions, and for early NOx emissions reduction projects. The approved cost recovery for these various environmental projects through customers’ bills began in January 2001.

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a potentially responsible party for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of December 31, 2002, Tampa Electric Company has estimated its ultimate financial liability to be approximately $20 million, and this amount has been reflected in the consolidated financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are recoverable through rates and are not expected to have a significant impact on customer prices.

The estimated amounts represent only the estimated portion of the cleanup costs attributable to Tampa Electric Company. The estimates to perform the work are based on actual estimates obtained from contractors or Tampa Electric Company’s experience with similar work adjusted for site specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

Allocation of the responsibility for remediation costs among Tampa Electric Company and other potentially responsible parties (PRPs) is based on each parties’ relative ownership interest in or usage of a site. Accordingly, Tampa Electric Company’s share of remediation costs varies with each site. In virtually all instances where other PRPs are involved, those PRPs are considered creditworthy.

Factors that could impact these estimates include the ability of other PRPs to pay their pro rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. These costs are recoverable through customer rates established in subsequent base rate proceedings.

Expenditures

During the five years ended Dec. 31, 2002, Tampa Electric spent $141.7 million excluding the Gannon repowering, on capital additions to meet environmental requirements, including $20.3 million at the Polk Power Station and approximately $83 million to install a new scrubber system at Big Bend Units 1 and 2 to meet Phase 2 SO2 emissions reduction requirements

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under the Clean Air Act Amendments of 1990. Tampa Electric spent an estimated $9.4 million in 2002 on environmental projects. Environmental expenditures are estimated at $4.9 million for 2003 and $20 million in total for 2004 through 2007. These totals exclude amounts required to comply with the EPA Consent Decree, which are discussed above.

In 2002, Tampa Electric spent approximately $9.4 million for compliance with EPA consent decree requirements at Big Bend Station for reduction of NOx and PM emissions and to improve the scrubber systems to reduce SO2 emissions. Should Tampa Electric choose to continue to burn coal at Big Bend Station, approximately $127.8 million will be spent during 2003 through 2007 for further reduction of NOx emissions. Estimated expenditures for the continued improvement of electrostatic precipitators for PM emissions reductions are $4.3 million during 2003 through 2007. Tampa Electric has also spent $550.0 million, excluding allowance for funds used during construction (AFUDC) and dismantlement, 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 three 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. PGS operates a natural gas distribution system that serves over 281,000 customers. The system includes approximately 9,000 miles of mains and over 4,500 miles of service lines. (See Franchise section on page 10 for a list of service areas.)

In 2002, the total throughput for PGS was 1.3 billion therms. Of this total throughput, 12 percent was gas purchased and resold to retail customers by PGS, 74 percent was third party supplied gas delivered for retail customers, and 14 percent was gas sold off-system. Industrial and power generation customers consumed approximately 70 percent of PGS’ annual therm volume, commercial customers used approximately 25 percent and the balance was 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 299 million therms annually to facilities involved in cogeneration.

Revenues and therms for PGS for the years ended Dec. 31, are as follows:

PGS had 635 employees as of Dec. 31, 2002. A total of 71 employees in six of PGS’ 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.

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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.

On June 27, 2002, PGS requested a $22.6 million annual base revenue increase. On Dec. 17, 2002, the FPSC authorized PGS to increase annual base revenues by $12.05 million. The new rates allow for a return on equity range of 10.25 to 12.25 percent with an 11.25 percent midpoint, which is the same as its previously allowed return on equity, and a capital structure of 57.43 percent equity. The increase went into effect on Jan. 16, 2003. Since its last rate increase 10 years ago, PGS has added more than 100,000 customers and expanded its pipeline system from 5,000 miles to 9,000 miles.

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 Regulation—Cost Recovery Clauses section of MD&A.

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 required natural gas utilities to offer transportation-only service to all non-residential customers. The net result of the unbundling is a shift from commodity sales to transportation sales. 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. PGS had over 9,500 transportation customers as of Dec. 31, 2002.

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, including electricity. 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 Florida, gas service is unbundled for all non-residential customers. In November 2000, PGS implemented its “NaturalChoice” program offering unbundled transportation service to all eligible 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 competing companies seeking to sell alternate fuels or transport gas through other facilities, thereby bypassing PGS facilities. In response to this competition, PGS has developed various programs, including the provision of transportation services at discounted rates. See the Regulation—Utility Competition:Gas section of MD&A.

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 three 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 56 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 two gate stations located northwest of Jacksonville.

In May 2002, Gulfstream Natural Gas Pipeline initiated service and is the first new pipeline serving peninsular Florida since 1959. PGS entered into a service agreement for capacity in 2002 and plans to bring gas from the Gulfstream pipeline into its system at four locations by the end of 2003.

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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 100 municipalities throughout Florida. These include the cities of Lakeland, Jacksonville, Daytona Beach, Eustis, Fort Myers, Ocala, 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 June 2003 through April 2031.

In March 2000, the City of Lakeland (City) filed suit against PGS and sought a declaration that it had the right to purchase PGS facilities located within the city limits. In October 2002, the City decided that it no longer desired to pursue owning the gas utility in Lakeland and agreed to voluntarily dismiss the lawsuit. The City and PGS entered into a new 10-year franchise agreement, similar in terms and conditions to the majority of the agreements PGS has with other municipalities.

Franchise fees payable by PGS, which totaled $6.2 million in 2002, 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’ 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 PGS, for certain superfund and former manufactured gas plant sites. See the previous discussion in the Environmental Matters section of Tampa Electric—Electric Operations on page 7.

Expenditures. During the five years ended Dec. 31, 2002, PGS has not incurred any material capital expenditures to meet environmental requirements, nor are any anticipated for 2003 through 2007.

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TECO POWER SERVICES

TECO Power Services (TPS) has subsidiaries that have interests in independent power projects in Florida, Virginia, Hawaii, Mississippi, Arkansas, Texas, Arizona and Guatemala, and has an investment in an unconsolidated affiliated entity that participates in an independent power project in the Czech Republic. TPS had 398 employees as of Dec. 31, 2002.

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 370-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 Tampa Electric and Seminole Electric Cooperative (Seminole Electric), a Florida electric cooperative that provides wholesale power to ten electric distribution cooperatives. Under the Seminole Electric agreements, Hardee Power agreed to supply Seminole Electric with an additional 145 megawatts of capacity during the first ten years of the contract, which ended on Dec. 31, 2002. This additional capacity was purchased from Tampa Electric’s coal-fired Big Bend Unit Four for resale to Seminole Electric. The 75-megawatt capacity expansion completed at Hardee Power Station in May 2000 is expected to serve Tampa Electric through 2012. The expansion consists of a General Electric combustion turbine operating in simple-cycle mode.

TPS owns 100 percent of Central Generadora Electrica San Jose, Ldta. (CGESJ), 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. In 1996, CGESJ signed a U.S. dollar-denominated power sales agreement (PPA) with Empresa Eléctrica de Guatemala, S.A. (EEGSA), a private distribution and generation company, to provide 120 megawatts of capacity for 15 years beginning in 2000. In 2001, CGESJ signed an option with EEGSA to extend that PPA for five years for approximately $2.5 million. In 2002, CGESJ began to transfer the port assets to Tecnologia Maritima, S.A. (TEMSA), a new TPS wholly-owned subsidiary. This transaction is expected to be completed in the first quarter of 2003. TEMSA, in addition to receiving the coal shipments for CGESJ, will be providing unloading services to third parties. 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 96.06-percent owned by TPS Guatemala One, Inc., a subsidiary of TPS and the owners of the Alborada Power Station, have a U.S. dollar-denominated PPA with EEGSA to provide 78 megawatts of capacity for a 15-year period ending in 2010. In 2001, TCAE signed an option with EEGSA to extend that PPA for five years at the end of its current term for approximately $2.9 million. EEGSA is responsible for providing the fuel for the plant, with TPS providing assistance in fuel administration. TPS had originally obtained $29 million of limited recourse financing from OPIC for the Alborada Power Station. In 2002, TCAE paid off its loan with OPIC with a portion of the proceeds from a non-recourse $30 million loan from Banco Industrial, a local bank in Guatemala. 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.

EEGSA serves 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 24 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. TPS has obtained political risk insurance for currency inconvertibility, expropriation and political violence covering up to 100 percent of TPS’ equity investment and economic returns.

In 1998, 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 provided capital and technical expertise to Mosbacher Power. In 1998, TPS, through TMPV, made certain loans to two existing projects under development by Mosbacher Power. Also in 1998, TPS, through TMPV, acquired approximately a 13 percent interest in a re-powered independent power project in the Czech Republic (the ECKG project). The facility completed its expansion to a total of 344 megawatts in the first quarter of 2000 and is currently in operation. In 2002, TPS purchased Mosbacher Power’s minority ownership interest in TMPV, thereby giving TPS a 100% ownership interest in TMPV. As part of the purchase, TPS received principal and interest due on its loans to Mosbacher Power. Also in 2002, TPS recorded a $5.8 million after-tax charge to adjust the valuation of the investment in the ECKG project in connection with the proposed sale of that investment.

TPS, through TMPV, has a 100-percent economic interest in Commonwealth Chesapeake Power Station (CCC), a 315-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.

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In the first quarter of 2001, TPS sold its minority interest in 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 the investment.

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 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). In February 2002, TPS provided an additional investment in the form of a loan in the amount of $44 million. These loans converted in accordance with their terms into an ownership interest on Jan. 3, 2003. The conversion gives TPS an opportunity for an effective economic interest of up to 75 percent of Panda’s 50-percent interest in the aggregate of 2,000-megawatts in these projects. The two projects, known as Guadalupe and Odessa, are located in Texas and operate as gas-fired, combined-cycle units. The projects were brought on line in phases beginning in December 2000, with all the capacity in service in August 2001.

In October 2000, TPS acquired from Genpower LLC full ownership of two independent power projects being developed in Arkansas and Mississippi with combined capacity of the two plants to be nearly 1,200 megawatts. The two 599-megawatt facilities, known as the Dell and McAdams projects, were designed to be natural gas-fired combined-cycle plants. Construction of these two projects was suspended in 2002. Construction on these plants was suspended at the end of 2002 due to low energy prices in the markets that these plants were expected to serve. Market conditions will be monitored to determine when these plans will be completed. At the time of suspension, approximately $690 million had been invested in these plants and TPS estimated at that time that the construction cost to complete these projects would be approximately $100 million. (See the TECO Power Services-Construction section of MD&A.)

In November 2000, TPS announced a joint venture with Panda to build, own and operate two natural gas power plants located in Arkansas and Arizona, known as the Union and Gila River projects. After taking into account the preferred return, TPS’ economic interest in the projects is estimated at 75-percent over the life of the projects. The 2,200-megawatt Union plant in Union County, Arkansas is under construction. The first phase began commercial operation in January 2003, and commercial operation of the entire facility is expected in the second quarter of 2003. 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 second quarter of 2003 with commercial operation of the entire facility in the third quarter of 2003. Electricity from this 2,145-megawatt plant 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 Panda’s interest in the joint venture for $60 million in 2007, unless Panda chooses to remain a partner by canceling the agreement and paying a cancellation fee. (See Transactions with Related and Certain Other Parties section of MD&A.)

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 $62 million. The equity bridge financing must be repaid in four equal installments. The first $125 million installment was paid in October 2002. The second installment is due in April 2003, and the third and fourth payments are due coincident with the conversion of the construction loans to term loans, which is expected shortly after Phase 4 completion (expected in the third quarter of 2003). The TPS equity investment in these projects at commercial operation is expected to be approximately $1.2 billion. (See the TECO Power Services-Construction section of MD&A.)

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.

Competition and Markets

The power plants that TPS is operating and constructing are located in markets with a history of high load growth. However, the general U.S. economic slowdown in 2001 and 2002 slowed the growth in demand for power in some of these markets. In addition, the slowdown of electricity deregulation initiatives across the U.S., including the markets that TPS will be serving, caused by the failure of deregulation in California, has allowed the traditional, incumbent utilities to continue to operate older, less efficient generating facilities in lieu of purchasing power from newer, more efficient independent power plants. These factors, combined with excess generating capacity that is either being built or has come on line in many markets, has depressed both spot and forward prices. Accordingly, TPS has ceased work on any new power plant developments, and is active in its efforts to mitigate its merchant exposure.

TPS’ ultimate long-term 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 would 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. In the meantime, until longer-term contracts can be signed, TPS is selling the output of these plants under a

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mix of spot market sales and shorter-term transactions. The shorter-term transactions are primarily forward sales of on-peak energy at prices reflective of current forward curves. TECO Energy’s policy is to balance power contract commitments with necessary purchases of natural gas in order to estimate the margins for such sales at the time of commitment. (See the TECO Power Services—Energy Markets section of MD&A.)

See the discussion of the risks applicable to TPS in the Investment Considerations section of MD&A. For financial information about geographic areas, see Note Q to the Consolidated Financial Statements.

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 997 employees as of Dec. 31, 2002.

TECO Transport’s subsidiaries perform substantial services for Tampa Electric. In 2002, approximately 57 percent of TECO Transport’s revenues were from third-party customers and approximately 43 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. Government’s cargo preference programs.

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 Gulf coast. 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 other land-based terminals.

Competition within TECO Transport’s 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 2002, 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 2002, TECO Transport spent $0.2 million for environmental compliance. Environmental expenditures are estimated at $0.3 million in 2003, 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, Rich Mountain Coal Company, Clintwood Elkhorn Mining Company, Pike-Letcher Land Company, Premier Elkhorn Coal Company, Bear Branch Coal Company and Perry County Coal Corporation. The TECO Coal subsidiaries own or control mineral rights, and own or operate surface and underground mines, synthetic fuel facilities and coal processing and loading facilities in eastern Kentucky, Virginia and Tennessee. TECO Coal intends to sell the majority of its interest in the synthetic fuel production facilities in 2003, but retain responsibility for operating the facilities. (See the Strategy and Outlook section of MD&A.)

TECO Coal and its subsidiaries had 676 employees as of Dec. 31, 2002.

In 2002, TECO Coal subsidiaries sold 9.4 million tons of coal, with approximately 99 percent, or 9.3 million tons,

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sold to parties other than Tampa Electric. Of the total sold, 3.8 million tons were produced and sold as synthetic fuel.

In November 2000, TECO Coal acquired Perry County Coal Corporation, which owns or controls in excess of 21 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 2.4 million tons of coal in 2002.

In January 2000, TECO Coal purchased synthetic fuel (synfuel) facilities which were relocated to the Premier Elkhorn and Clintwood Elkhorn mines. The 3.8 million tons of synfuel produced in 2002 replaced some of TECO Coal’s conventional coal production in 2002. 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.

The Section 29 tax credit is determined annually and is estimated to be $1.08 per million Btu in 2002, and was $1.08 per million Btu in 2001 and $1.06 per million Btu in 2000. This rate escalates with inflation but could be limited by domestic oil prices. In 2002, domestic oil prices would have had to exceed $49 per barrel for the limitation to have been effective. In 2002, TECO Coal’s Section 29 tax credits were $107.3 million, compared to $86.2 million in 2001 and $52.1 million in 2000.

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 2002, TECO Coal spent approximately $4.5 million on environmental protection and reclamation programs. TECO Coal expects to spend a similar amount in 2003 on these programs.

Coal mining operations are also subject to the Surface Mining Control and Reclamation Act of 1977 which places a charge of $0.15 and $0.35 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 SOLUTIONS

TECO Solutions was formed to support TECO Energy’s strategy of offering customers (primarily in Florida) a comprehensive and competitive package of energy services and products, including energy-efficient engineering and construction and gas management services. Operating companies under TECO Solutions include TECO Energy Services, Inc. (formerly TECO BGA, Inc. and BCH Mechanical, Inc. and its affiliated companies), Prior Energy Corporation, TECO Gas Services Inc., TECO Properties Corporation, TECO Propane Ventures LLC (TPV) and TECO Partners, Inc., with total employees of 714 as of Dec. 31, 2002.

TECO Energy Services is comprised of TECO BGA and BCH Mechanical and its affiliated companies (BCH). TECO BGA is an engineering energy services company headquartered in Tampa. It has six 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.

BCH, one of Florida’s leading mechanical contracting firms, is 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.

Prior Energy, a leading natural gas management company, is headquartered in Mobile, Alabama and serves customers throughout the Southeast. Prior Energy handles all facets of natural gas energy management services for large industrial, power generation utilities, municipal and other governmental agency customers, including natural gas acquisition and supply management, transportation management, asset management and consulting services. Prior Energy owns no operating assets.

TECO Gas Services provides gas management and marketing services similar to Prior Energy for large municipal, industrial, commercial and cogeneration facilities primarily in Florida. 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.

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TPV holds TECO Energy’s propane business investment. In 2000, TECO Energy combined its propane operations with three other southeastern propane companies to form U.S. Propane. In a series of transactions, U.S. Propane combined with Heritage Holdings, Inc. As a result, TPV owns a 38-percent interest in the general partner that manages Heritage Propane Partners, L.P. (NYSE:HPG) and that general partner owns an approximate 29-percent limited partnership interest in Heritage Propane Partners, L.P. TPV owns no operating assets.

TECO COALBED METHANE

TECO Coalbed Methane had developed jointly with another entity the natural gas potential of Alabama’s Black Warrior Basin.

Production from TECO Coalbed Methane’s reserves was eligible for Section 29 non-conventional fuels tax credits through 2002. The credit is estimated to be $1.10 per million Btu for 2002 and was $1.08 per million Btu in 2001 and $1.06 per million Btu in 2000. This rate escalated with inflation but could be limited by domestic oil prices. In 2002, domestic oil prices would have had to exceed $49 per barrel for this limitation to have been effective. In 2002, TECO Coalbed Methane’s Section 29 tax credits were $15.9 million, compared to $16.1 million in 2001. TECO Coalbed Methane’s operations are subject to federal, state and local regulations for air emissions and water and waste disposal.

In September 2002, TECO Energy initiated activities to sell the TECO Coalbed Methane gas assets. That sale was substantially completed in December 2002 to the Municipal Gas Authority of Georgia. Proceeds for the sale were $140 million, of which $42 million was paid in cash at closing and $98 million was paid in January 2003. TECO Coalbed Methane’s results are accounted for as discontinued operations for all periods reported.

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, 2002, Tampa Electric had five electric generating plants and five combustion turbine units in service with a total net winter generating capability of 3,784 megawatts, including Big Bend (1,759-MW capability from four coal units), Gannon (1,107-MW capability from six coal units), Hookers Point (90-MW capability from five oil units), Phillips (37-MW capability from two diesel units), Polk (260-MW capability from one integrated gasification combined cycle (IGCC) unit)) and three combustion turbine units (CTs) located at the Big Bend (165-MW) and two CTs at Polk (360-MW). Additionally, Tampa Electric has 6-MW of generating capability from generation units located at the Howard Curren Advanced Waste Water Treatment Plant in the City of Tampa. Tampa Electric also leases various distributive generation units (50-MW) at Hookers Point. 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 and was retired from service in January 2003. Hookers Point Station’s Unit 5 (67-MW) was placed on long-term standby in January 2001. All units at Hookers Point were retired from service in January 2003.

Engineering for repowering Gannon Station began in 2000 (see the Environmental Compliance section of MD&A), 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 187 substations having an aggregate transformer capacity of 17,677,068 KVA. The transmission system consists of approximately 1,200 pole miles of high voltage transmission lines, and the distribution system consists of 7,019 pole miles of overhead lines and 3,143 trench miles of underground lines. As of Dec. 31, 2002, there were 597,146 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.

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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 13,500 miles of pipe, including approximately 9,000 miles of mains and over 4,500 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 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 100-percent economic interest in Commonwealth Chesapeake Company, LLC, which owns approximately 105 acres of land outside of New Church, in Accomack County, Virginia on which the 315-megawatt oil-fired single cycle Commonwealth Chesapeake Power Station is located.

TPS Dell, LLC, owns approximately 100 acres in the City of Dell in Mississippi County, Arkansas, on which the 599-megawatt gas-fired combined-cycle Dell electric generation plant has been under construction. TPS McAdams, LLC, owns approximately 210 acres of land in McAdams and Sallis in Attala County, Mississippi, on which the 599-megawatt gas-fired combined cycle McAdams electric generation plant has been under construction. Construction on these projects was suspended at the end of 2002 due to projected low energy prices in the markets these plants were expected to serve. Markets will be monitored to determine when these plants will be completed.

TPS, through its subsidiary TPS Hamakua Land, Inc., has a 50-percent interest in Hamakua Land Partnership, LLP, which 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, LP owns 40 acres of land in Hidalgo County, Texas on which the 477-megawatt gas-fired combined cycle Frontera electric generation plant is located.

TPS has a 50-percent ownership interest in TECO-Panda Generating Company, LP, which owns two power plant 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 2,200 MW gas-fired combined-cycle Union electric generation plant is under construction. The first 550-megawatt power block of Union began operating in January 2003. Panda Gila River, LP owns approximately 1,099 acres of land in Maricopa County, Arizona, on which the approximately 2,145-megawatt gas-fired combined-cycle Gila River 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 727 river barges, approximately 69 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.

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As of Dec. 31, 2002, TECO Ocean Shipping owned and operated a fleet of 10 ocean-going tug/barge units, a 33,500 short ton ocean-going ship, a 40,900 short ton ocean-going ship, and a 41,400 short ton ocean-going ship, with a combined cargo capacity of over 420,000 tons.

TECO COAL

TECO Coal, through its subsidiaries, controls approximately 203,000 acres of coal reserves and mining property in Kentucky, Virginia and Tennessee.

Property

Gatliff Coal Company controls approximately 35,000 acres of coal and mining properties and has operations in Campbell County, Tennessee, as well as in Bell, Knox and Whitley Counties, Kentucky. In eastern Kentucky, Bear Branch Coal Company and Perry County Coal Corporation control 50,000 acres of coal reserves and operate in Perry, Knot and Leslie Counties. Additionally in eastern Kentucky, Premier Elkhorn Coal Company and Pike-Letcher Land Company are located in Letcher and Pike Counties where they control 50,000 acres of properties. Clintwood Elkhorn Mining also operates in Pike County, Kentucky, as well as Buchannan County, Virginia. Clintwood Elkhorn controls 68,000 acres of property.

In situations where property is controlled by lease, the lease terms are sufficient to ensure that the reserves for the associated operation can be mined within the initial lease term. If, however, extensions are necessary, provisions have been made within the original lease, whereby extensions may be granted upon payment of minimum royalties.

Facilities

Coal mined by the operating companies of TECO Coal is processed and shipped from facilities located at each of the operating companies, with Clintwood Elkhorn having two facilities, one at Biggs, Kentucky and one at Hurley, Virginia. The equipment at each facility is in good condition and regularly maintained by qualified personnel. Major expansions are currently on-going at the Perry County Coal facility that will enable the plant to meet the additional production requirements brought about by the opening of the Bear Branch Elkhorn 4-seam underground mine. The following is a summary of the TECO Coal processing facilities.

Significant projects initiated in 2002 include: an underground mine at Bear Branch, an underground mine at Premier Elkhorn, and a surface operation at Clintwood Elkhorn.

Coal Reserves

As of Dec. 31, 2002, the TECO Coal operating companies have a combined estimated 224.5 million tons of recoverable reserves, all of which are assigned. The reserves are proven and probable. All of the reserves consist of High Vol A Bituminous coal. Reserves are generally considered to be tonnages that are proven and probable and meet the generally accepted mining criteria including, but not limited to, mining height, preparation plant recovery and strip ratio. These reserves are generally projected to be mined and sold at a profit, based on year-end price and cost levels. When calculating reserves, TECO Coal has assumed the following recovery rates for the various mining methods.

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The following is a summary of the qualities associated with each of the operations.

The following table shows a further breakdown of product by geographic region with projected market type.

TECO Coal’s reserves are based on over 1,700 data points, including drill holes, prospect measurements, and mine measurements. Reserve classification is determined by evaluation of engineering and geologic information along with economic analysis. These reserves are adjusted periodically to reflect fluctuations in the economics in the market and/or changes in engineering parameters and/or geologic conditions. The information is assembled by qualified geologists and engineers located throughout the company. The information is constantly updated to reflect new data for existing property as well as new acquisitions and depleted reserves. Information is entered into a computer modeling program from which preliminary reserves estimations are generated. Final determinations of reserves are made after in-house geologists have reviewed the computer models and adjusted the grids to better reflect regional trends.

TECO COALBED METHANE

The sale of TECO Coalbed Methane’s gas assets was substantially completed in December 2002, and the final proceeds were paid in January 2003. (See Business—TECO Coalbed Methane section.) TECO Coalbed Methane’s gas production for 2002 was 14.2 billion cubic feet (Bcf), at an effective gas price, including the effect of hedging, of about $2.80 per thousand cubic feet (Mcf) compared to production of 15 Bcf in 2001 at an effective gas price, including the effects of hedging, of about $3.66 Mcf.

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Item 3. LEGAL PROCEEDINGS.

TM Power Ventures, LLC (“TMPV”) a subsidiary of TECO Power Services Corporation, holds a membership and an ownership interest in Commonwealth Chesapeake Company, L.L.C. (“CCC”), owner of the Commonwealth Chesapeake project located in Virginia on the Delmarva Peninsula (“CCP”). TPS, through TMPV, currently has a 100-percent ownership interest in CCP as a result of TPS’ purchase of Mosbacher Power Partners minority interest in TMPV in 2002. (See page 11). TMPV has been arbitrating certain disputes with NCP of Virginia, LLC (NCP), a member in CCC. In addition to its membership interest in CCC entitling NCP to a priority distribution in recognition of certain contributions it made to CCP, NCP has an option to acquire up to a 50-percent economic interest in CCP. The arbitration panel issued an interim award finding in favor of NCP on issues it alleged to have adversely affected NCP’s ability to find an investor to support the exercise of its option to acquire an ownership interest and establishing as the remedy a buyout of NCP’s interests, including its option to acquire the ownership interest, the related terminal value of such ownership, and its right to receive priority distributions. The panel directed the parties to provide information with respect to the value of NCP’s interest and file briefs by Feb. 14, 2003 focusing on the appropriate discount rate to apply and changes, if any, to the methodology set out by the panel, with reply briefs to be filed by March 21, 2003. A final award is anticipated to be issued thereafter establishing the buyout price. Based on the language of the interim award and the methodology established for calculating the value of NCP’s interest, the Company believes that, if properly calculated, the buyout price will be commercially reasonable and will not have a material impact on the Company’s earnings or cash requirements; however, the briefs filed by the respective parties indicate a wide disparity in both the value of the buyout and the methodologies used. The Company believes the buyout plus attorneys fees to be less than $10 million, while NCP has claimed a value of approximately $50 million. Accordingly, the amount the panel will establish for the buyout cannot be determined at this time.

See also the Enron Related Matters and Superfund and Former Manufactured Gas Plant Sites sections of MD&A.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

No matter was submitted during the fourth quarter of 2002 to a vote of TECO Energy’s security holders, through the solicitation of proxies or otherwise.

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EXECUTIVE OFFICERS OF THE REGISTRANT

The names, ages, current positions and principal occupations during the last five years of the current executive officers of TECO Energy are described below.

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 22, 2003, and until such officer’s successor is elected and qualified.

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PART II

Item 5. MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.

The following table shows the high and low 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.

The approximate number of shareholders of record of common stock of TECO Energy as of Feb. 28, 2003 was 23,482.

TECO Energy’s primary source of funds to pay dividends to its common stockholders is dividends from its operating companies, including Tampa Electric Company. Tampa Electric’s first mortgage bonds and certain long-term debt issues at PGS 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 2002. (See Restrictions on Dividend Payments and Transfer of Assets section in Note A to the Consolidated Financial Statements.)

TECO Energy’s 10.5% 5-year notes issued in November 2002 contain covenants that will, among other things, in the event of certain debt ratings downgrades, require TECO Energy to achieve certain debt service coverage levels in order to pay dividends or distributions or make certain investments, and limit additional liens and issue additional indebtedness. (See Covenants in Financing Agreements section of MD&A.)

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 Trusts 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.

All of Tampa Electric Company’s common stock is owned by TECO Energy, Inc. and, therefore, there is no market for the stock. Tampa Electric Company pays dividends substantially equal to its net income applicable to common stock to TECO Energy. Such dividends totaled $197.4 million in 2002 and $171.8 million for 2001. See Note A – Restrictions on Dividend Payments and Transfer of Assets in the Consolidated Notes to the Financial Statements for Tampa Electric Company for a description of restrictions on dividends on its common stock.

See Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management for the tabular disclosure of TECO Energy’s Equity Compensation plans.

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Item 6. SELECTED FINANCIAL DATA.

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Item 7. MANAGEMENT’S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION & RESULTS OF OPERATIONS.

This Management’s Discussion and Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. These forward-looking statements include references to TECO Energy’s anticipated capital investments, financing requirements, project completion dates, future transactions and other plans. Certain factors that could cause actual results to differ materially from those projected in these forward-looking statements include the following: energy price changes affecting TECO Power Services’ (TPS’) merchant plants; TPS’ ability to sell the output of the merchant plants operating or under construction at a premium to the forward curve prices and to obtain power contracts to reduce earnings volatility; any unanticipated need for additional debt or equity capital that might result from lower than expected cash flow or higher than projected capital requirements; TECO Energy’s ability to successfully complete the sale of its synthetic fuel and gasification facilities to successfully complete its cash generation plan; and TECO Energy’s ability to maintain credit ratings sufficient to avoid posting letters of credit relating to TPS’ construction loans and to avoid providing additional assurances to counterparties. Other factors include: general economic conditions, particularly those in Tampa Electric’s service area affecting energy sales; weather variations affecting energy sales and operating costs; potential competitive changes in the electric and gas industries, particularly in the area of retail competition; regulatory actions affecting Tampa Electric, Peoples Gas System or TPS; commodity price changes affecting the competitive positions of Tampa Electric and Peoples Gas System, as well as the margins at TECO Coal; changes in and compliance with environmental regulations that may impose additional costs or curtail some activities; TPS’ ability to successfully construct and operate its projects on schedule and within budget; the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures; interest rates, credit ratings and other factors that could impact TECO Energy’s ability to obtain access to sufficient capital on satisfactory terms; and TECO Coal’s ability to successfully operate its synthetic fuel production facilities in a manner qualifying for Section 29 federal income tax credits, the use of which could be limited by TECO Energy’s taxable income or by changes in law, regulation or administration. Some of these factors and others are discussed more fully under “Investment Considerations.”

2002 Earnings Summary

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TECO Energy’s revenues increased by more than 7 percent in 2002 to $2.7 billion; revenues in 2001 increased 11.9 percent to $2.5 billion. In 2002, net income from continuing operations rose almost 9 percent to $298.2 million, up from $273.8 million in 2001. Net income from continuing operations was $227.5 million in 2000. Earnings per share—basic from continuing operations were $1.95 per share in 2002 compared with $2.04 per share in 2001. The number of average shares outstanding at Dec. 31, 2002 was almost 14 percent higher than at Dec. 31, 2001. Earnings per share—basic from continuing operations were $1.81 in 2000.

Included in the 2002 results from continuing operations are a $34.1-million pretax ($20.9 million after-tax) charge related to a debt refinancing and a $5.8 million after-tax asset valuation charge related to the proposed sale of TPS’ minority interest in power generating facilities in the Czech Republic. Excluding these unusual items, non-Generally Accepted Accounting Principles (GAAP), or pro forma, net income from continuing operations rose 19 percent to $324.9 million or from $2.04 per share in 2001 to $2.12 per share in 2002. Results from discontinued operations reflect results at the coalbed methane business, which was sold in December 2002.

Total net income and earnings per share, including continuing operations and discontinued operations, were $330.1 million and $2.15 per share, respectively. Total non-GAAP net income and earnings per share, excluding the debt refinancing and asset valuation charges and the $7.7 million gain on the sale of TECO Coalbed Methane, were $349.1 million and $2.28 per share, respectively.

The 2002 results reflect continued customer growth and increased energy usage in the Florida utility operations, higher allowance for funds used during construction (AFUDC—non-cash credit to income with a corresponding increase in utility plant which represents the cost of borrowed funds and a reasonable return on the equity funds used for construction) at Tampa Electric, improved results at TPS, and increased synthetic fuel production at TECO Coal. These improvements were partially offset by lower results at TECO Transport.

Net income from continuing operations in 2001 was $273.8 million, up more than 20 percent from $227.5 million in 2000. These results reflected 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, 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 and a $6.1 million after-tax asset valuation charge related to TPS’ sale of its interest in Energía Global International, Ltd. (EGI).

Strategy and Outlook

In late 1999, TECO Energy announced a three-pronged business strategy which was to focus on its Florida operations, which include Tampa Electric, Peoples Gas System (PGS) and the Florida energy services businesses, TECO Solutions; to expand its domestic independent power operations at TPS; and to use the returns of its family of other profitable unregulated businesses to support growth. Since that time, the company has undertaken a number of initiatives to advance the announced strategy. These initiatives include continued development of the regulated electric and gas businesses in Florida, including significant additions to Tampa Electric’s electric generation facilities, development of independent power generation projects in the Sunbelt of the United States and continued good operations and returns from its family of other unregulated businesses. However, conditions in energy markets and the independent power business have changed since then.

In 2001, future wholesale power prices declined significantly in markets across the country due to a combination of the slowing of wholesale electric competition; uneconomic dispatch; the U.S. economic slowdown; and the large amount of new generating capacity either completed or under construction and expected to come online in 2002 and 2003. The price outlook remained weak throughout 2002 and the prospects for price recovery in 2003 are uncertain. The low power prices have caused weaker earnings expectations from independent power projects and have caused some developers to cancel or delay projects in some markets.

In light of the capital required to complete the committed regulated and unregulated power plant projects, during 2002 TECO Energy took a number of steps to provide the needed cash while, at the same time, strengthening its balance sheet. These steps included accessing the capital markets for funding, initiating other cash generation measures and reducing capital expenditures. During 2002, the company issued new common equity on two occasions totaling $553 million in net proceeds. In January 2002, the company issued $436 million in net proceeds of mandatorily convertible equity units, which will convert to TECO Energy common shares in January 2005. In addition, the company has reduced its capital expenditure forecast for 2002 through 2004 on two separate occasions. The first reduction in January 2002 totaled approximately $700 million, primarily through delaying, for an extended period, generation projects that were not yet under construction for TPS and Tampa Electric. The second reduction was effected in September as part of a comprehensive cash business plan.

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In September 2002, the company announced a preliminary 2003 business plan that focused on the generation of cash to support the construction of the Union and Gila River power stations at TPS and the Gannon to Bayside repowering project at Tampa Electric so as to avoid accessing the capital markets for incremental debt in 2003. This was done in the face of downgrades by equity analysts and the credit rating agencies of both TECO Energy and other companies in the energy sector. The industry’s situation deteriorated in late 2002 to the state of a severe credit crisis, highlighting the importance of TECO Energy’s execution of the announced plan.

The major components of the plan included: 1) a reduction of capital expenditures of $250 million, including the suspension of construction of the Dell and McAdams power stations, changing the timing of the completion of Bayside Unit 2 and general capital spending reductions at all of the companies, which allowed TECO Energy to sustain its previously forecasted capital expenditure levels; 2) $400 million from the sale of the TECO Coalbed Methane gas assets, the proposed sale of the majority of its interest in facilities that produce synthetic fuel which qualify for Section 29 tax credits at TECO Coal, and the proposed sale of the coal gasification unit at Tampa Electric’s Polk Power Station; and 3) $250 million of cash from other financial transactions or asset sales including the repatriation of cash and additional cash from non-recourse refinancing on generating facilities in Guatemala. In addition, TECO Energy ceased work on any new development in the independent power area beyond the already announced and initiated activities.

TECO Energy expects an extended period of lower earnings and to be in a weaker financial position during the current cycle of low wholesale power prices. As previously discussed, the company took decisive steps during 2002 to improve its financial position. The company will continue to take steps as necessary to position itself for a return to a stronger financial position and to a return to earnings growth in the future.

During this period of low wholesale power prices, TECO Energy expects to continue to benefit from deriving the majority of net income and cash flow from its regulated businesses, Tampa Electric and PGS, which operate in one of the highest growth utility markets in the nation. In 2003, about 75 percent of net income is expected to come from regulated utility operations in Florida. Growth is expected to continue in Florida because the state’s economy, with its small industrial base, was not impacted by the economic slowdown to the same degree as some manufacturing-based areas of the country.

Operating Results

Management’s Discussion & Analysis of Financial Condition & Results of Operations utilize TECO Energy’s consolidated financial statements, which have been prepared in accordance with GAAP, to analyze the financial condition of the company.

TECO Energy’s reported operating results are affected by a number of critical accounting policies that include such items as accounting for regulated activities, accounting for derivatives, asset impairment testing, accounting for unconsolidated affiliates and others. (See the Critical Accounting Policies and Estimates section.)

The following table shows the unconsolidated revenues, net income and earnings per share contributions from continuing operations of the significant business segments. (See Note Q to the Consolidated Financial Statements.)

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