Form 10-K for TECO Energy, Inc. and Tampa Electric Company

10-K 1 d10k.htm FORM 10-K FOR TECO ENERGY, INC. AND TAMPA ELECTRIC COMPANY Form 10-K for TECO Energy, Inc. and Tampa Electric Company

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2002

Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from to

Commission File No.	Exact name of each Registrant as specified in its charter, state of incorporation, address of principal executive offices, telephone number	I.R.S. Employer Identification Number
1-8180	TECO ENERGY, INC.	59-2052286
	(a Florida Corporation)
	TECO Plaza
	702 N. Franklin Street
	Tampa, Florida 33602
	(813) 228-4111
1-5007	TAMPA ELECTRIC COMPANY	59-0475140
	(a Florida Corporation)
	TECO Plaza
	702 N. Franklin Street
	Tampa, Florida 33602
	(813) 228-4111

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

Title of each class		Name of each exchange on which registered
TECO Energy, Inc.
Common Stock, $1.00 par value		New York Stock Exchange
Common Stock Purchase Rights		New York Stock Exchange
Equity Security Units		New York Stock Exchange

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

(millions)	2002			2001			2000
Tampa Electric	$	1,583.2		$	1,412.7		$	1,353.8
Peoples Gas System		318.1			352.9			314.5

Total regulated businesses		1,901.3			1,765.6			1,668.3
TECO Power Services		309.8			287.1			199.1
TECO Transport		254.6			274.9			269.8
TECO Coal		317.1			303.4			232.8
Other unregulated businesses		122.1			106.9			81.8

		2,904.9			2,737.9			2,451.8
Other and eliminations		(229.1	)		(249.8	)		(228.7	)

	$	2,675.8		$	2,488.1		$	2,223.1

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

(millions)	2002		2001		2000
Residential	$	753.9	$	659.8	$	613.3
Commercial		459.6		409.7		377.1
Industrial-Phosphate		74.3		57.0		61.6
Industrial-Other		83.8		71.8		62.6
Other retail sales of electricity		117.4		103.0		95.0
Sales for resale		67.7		82.4		109.1
Other		26.5		29.0		35.1

	$	1,583.2	$	1,412.7	$	1,353.8

Megawatt-hour Sales

(millions)	2002	2001	2000
Residential	8,046	7,594	7,369
Commercial	5,832	5,685	5,541
Industrial	2,612	2,329	2,390
Other retail sales of electricity	1,435	1,368	1,338
Sales for resale	1,084	1,499	2,564

	19,009	18,475	19,202

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.

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

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:

Average cost per million Btu:	2002		2001		2000		1999		1998
Coal	$	1.93	$	2.06	$	1.92	$	2.00	$	1.99
Oil	$	5.33	$	5.79	$	5.33	$	3.09	$	3.14
Gas (Natural)	$	5.86	$	4.84	$	5.49		—		—
Composite	$	2.11	$	2.19	$	2.07	$	2.03	$	2.03
Average cost per ton of coal burned	$	45.04	$	47.53	$	44.36	$	44.63	$	44.44

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.

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

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:

	Revenues						Therms
(millions)	2002		2001		2000		2002	2001	2000
Residential	$	76.6	$	88.2	$	73.2	60.2	58.8	57.6
Commercial		122.3		163.6		145.8	327.6	308.9	292.1
Industrial		80.3		50.7		51.7	423.8	346.5	374.1
Power Generation		11.4		11.3		10.7	492.6	403.5	418.6
Other revenues		27.5		39.1		33.0	—	—	—

Total	$	318.1	$	352.9	$	314.4	1,304.2	1,117.7	1,142.4

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.

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.

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.

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.

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.

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,

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.

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.

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.

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.

Company	Facility	Location	Railroad Service	Utility Service
Gatliff Coal	Gatliff Plant	Gatliff, KY	CSX Railroad	Cumberland Valley Electric/
				Jellico Electric Power
Clintwood Elkhorn	Clintwood #2 Plant	Biggs, KY	Norfolk Southern	American Electric Power
Clintwood Elkhorn	Clintwood #3 Plant	Hurley, VA	Norfolk Southern	American Electric Power
Premier Elkhorn	Burk Branch Plant	Myra, KY	CSX Railroad	American Electric Power
Perry County Coal	Perry County Plant	Hazard, KY	CSX Railroad	American Electric Power

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.

		Mining Recovery Rates
Underground		55%
Contour, Surface		85%
Point Removal/Mt. Top		90%
Auger		30%
Highwall Miner		50%

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

Company	BTU/lb.	Average % Ash	Quality % Sulfur	Assigned % Owned	Reserves % Leased	Surface Reserves (000s)	Underground Reserves (000s)	Total Reserves (000s)
Gatliff Coal	14,586	3.84	0.96	0	100	2,700	10,908	13,608
Perry County Coal	14,076	7.74	0.97	0	100	4,703	16,489	21,192
Bear Branch	14,223	6.70	0.99	0	100	—	70,558	70,558
Premier Elkhorn Coal/ Pike Letcher Land (1)	13,976	6.78	1.16	90	10	19,882	55,879	75,761
Clintwood Elkhorn Mining	14,282	7.51	1.06	10	90	12,641	30,785	43,426

Total Reserves	14,159	6.81	1.06			39,926	184,619	224,545

(1)

The Premier Elkhorn/Pike Letcher Land reserves were reduced from the 2001 amounts due to unfavorable economic conditions.

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

Region/Company	Product	BTU/lb.	% Ash	% Sulfur	Reserves (000s)	% by Region
Eastern Kentucky
Gatliff Coal	Steam coal	14,586	3.84	0.96	13,608	6.06
Perry County Coal	Steam coal	14,076	7.74	0.97	21,192	9.44
Bear Branch Coal	Steam coal	14,223	6.70	0.99	70,558	31.42
Premier/Pike Letcher Land	Steam coal	13,976	6.78	1.16	75,761	33.74
Clintwood	Steam coal	12,713	13.40	1.08	1,500	0.67
Clintwood	Metallurgical coal	14,429	6.51	1.08	20,626	9.19

					203,245	90.52

Southwestern Virginia
Clintwood	Steam coal	12,713	13.40	1.08	7,159	4.96
Clintwood	Metallurgical coal	14,621	5.37	1.01	14,141	4.52

					21,300	9.48

Total					224,545	100.00

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.

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.

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.

Name	Age	Current Positions and Principal Occupations During Last Five Years

Robert D. Fagan	58	Chairman of the Board, President and Chief Executive Officer, December 1999 to date; President and Chief Executive Officer, May 1999 to December 1999; and prior thereto, President of PP&L Global, Inc. (diversified energy company), Fairfax, Virginia.

William N. Cantrell	50	President of TECO Solutions, September 2000 to date and President of Peoples Gas System June 1997 to date.

Royston K. Eustace	61	Senior Vice President-Business Development, April 1998 to date; and prior thereto, Vice President-Strategic Planning and Business Development.

Gordon L. Gillette	43	Senior Vice President-Finance and Chief Financial Officer, April 2001 to date; Vice President-Finance and Chief Financial Officer, April 1998 to April 2001; Vice President-Regulatory Affairs, April 1997 to April 1998.

Richard Lehfeldt	51	Senior Vice President-External Affairs, November 1999 to date; and prior thereto, Vice President and Assistant General Counsel of Edison Mission Energy (independent power company), Irvine, California.

Richard E. Ludwig	57	President of TECO Power Services Corporation, April 1989 to date.

Sheila M. McDevitt	56	Senior Vice President-General Counsel, April 2001 to date; Vice President-General Counsel, January 1999 to April 2001; and prior thereto, Vice President-Assistant General Counsel.

John B. Ramil	47	Executive Vice President—TECO Energy, Inc., December 2002 to date and President of Tampa Electric Company, April 1998 to date; Vice President-Finance and Chief Financial Officer, November 1997 to April 1998.

D. Jeffrey Rankin	56	President of TECO Transport Corporation, October 1987 to date.

J. J. Shackleford	56	President of TECO Coal Corporation, March 1986 to date.

There is no family relationship between any of the persons named above. The term of office of each officer extends to the meeting of the Board of Directors following the next annual meeting of shareholders, scheduled to be held on April 22, 2003, and until such officer’s successor is elected and qualified.

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.

	1st Quarter		2nd Quarter		3rd Quarter		4th Quarter
2002
High	$	28.940	$	29.050	$	24.710	$	16.480
Low	$	23.400	$	22.700	$	14.200	$	10.020
Close	$	28.630	$	24.750	$	15.880	$	15.470
Dividend	$	0.345	$	0.355	$	0.355	$	0.355
2001
High	$	32.125	$	32.970	$	31.650	$	28.300
Low	$	26.100	$	28.780	$	25.530	$	24.750
Close	$	29.960	$	30.500	$	27.100	$	26.240
Dividend	$	0.335	$	0.345	$	0.345	$	0.345

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.)

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.

Item 6. SELECTED FINANCIAL DATA.

	Year ended Dec. 31,
(millions, except per share amounts)	2002			2001			2000			1999			1998
Revenues	$	2,675.8		$	2,488.1		$	2,223.1		$	1,932.6		$	1,905.1
Net income from continuing operations	$	298.2	(1)	$	273.8	(1)	$	227.5	(1)	$	179.2	(2)	$	179.2	(3)
Income from discontinued operations		26.1			21.9			12.6			-16.3			10.3
Income tax benefit—discontinued operations		-5.8			-8.0			-10.8			-23.2			-17.0

Net income from discontinued operations		31.9			29.9			23.4			6.9			27.3

Net income	$	330.1	(1)	$	303.7	(1)	$	250.9	(1)	$	186.1	(2)	$	206.5	(3)

Total assets	$	8,637.8		$	6,763.4		$	5,774.3		$	4,733.0		$	4,218.3
Long-term debt	$	3,324.3		$	1,842.5		$	1,374.6		$	1,207.8		$	1,279.6
Earnings per share (EPS)—basic:
From continuing operations	$	1.95	(1)	$	2.04	(1)	$	1.81	(1)	$	1.37	(2)	$	1.36	(3)
From discontinued operations		20			22			18			05			21

EPS basic	$	2.15	(1)	$	2.26	(1)	$	1.99	(1)	$	1.42	(2)	$	1.57	(3)

Dividends paid per common share (4)	$	1.41		$	1.37		$	1.33		$	1.285		$	1.225

(1)

Includes other non-operating items affecting net income (see Note L to the Consolidated Financial Statements).

(2)

Includes the effect of charges, which reduced net income by $19.6 million and earnings per share by $0.15 in 1999.

(3)

Includes the effect of charges, which reduced net income by $19.6 million and earnings per share by $0.15 in 1998.

(4)

Dividend paid on TECO Energy common stock.

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

	2002			Change		2001			Change		2000
Consolidated revenues (millions)	$	2,675.8		7.5	%	$	2,488.1		11.9	%	$	2,223.1

Earnings per share—basic
Continuing operations	$	1.95		-4.4	%	$	2.04		12.7	%	$	1.81
Discontinued operations		.20		-9.1	%		.22		22.2	%		.18

Earnings per share	$	2.15		-4.9	%	$	2.26		13.6	%	$	1.99

Earnings per share—diluted
Continuing operations	$	1.95		-3.4	%	$	2.02		12.8	%	$	1.79
Discontinued operations		.20		-9.1	%		.22		22.2	%		.18

Earnings per share	$	2.15		-4.0	%	$	2.24		13.7	%	$	1.97

Net income from continuing operations (millions)	$	298.2		8.9	%	$	273.8		20.3	%	$	227.5

Average common shares outstanding
Basic (millions)		153.2	(3)	13.9	%		134.5	(2)	6.8	%		125.9	(1)
Diluted (millions)		153.3	(3)	13.2	%		135.4	(2)	7.2	%		126.3	(1)

Return on average common equity(4)		14.3	%				16.5	%				16.7	%

(1)

Average shares outstanding reflects the repurchase of 1.6 million shares in 2000.

(2)

Average shares outstanding for 2001 reflects the issuance of 8.625 million shares in March 2001 and 3.5 million shares in October 2001.

(3)

Average shares outstanding for 2002 reflects the issuance of 15.525 million shares in June 2002 and 19.385 million shares in October 2002.

(4)

Includes results from Discontinued operations (TECO Coalbed Methane).

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.

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.)

(millions) Except per share amounts	2002			Change		2001			Change		2000
Unconsolidated Revenues (1)
Regulated Companies
Tampa Electric	$	1,583.2		12.1	%	$	1,412.7		4.4	%	$	1,353.8
Peoples Gas System		318.1		-9.9	%		352.9		12.2	%		314.5

Total Regulated	$	1,901.3		7.7	%	$	1,765.6		5.8	%	$	1,668.3

Unregulated Companies
TECO Power Services	$	309.8		7.9	%	$	287.1		44.2	%	$	199.1
TECO Transport		254.6		-7.4	%		274.9		1.9	%		269.8
TECO Coal		317.1		4.5	%		303.4		30.3	%		232.8
Other unregulated businesses		122.1		14.2	%		106.9		30.5	%		81.8

Total Unregulated	$	1,003.6		3.2	%	$	972.3		24.1	%	$	783.5

Net Income (2)
Regulated Companies
Tampa Electric	$	171.8		11.6	%	$	154.0		6.6	%	$	144.5
Peoples Gas System		24.2		4.8	%		23.1		6.0	%		21.8

Total Regulated		196.0		10.7	%		177.1		6.5	%		166.3

Unregulated Companies
TECO Power Services		34.1		26.8	%		26.9		18.0	%		22.8
TECO Transport		21.0		-23.9	%		27.6		-5.5	%		29.2
TECO Coal		76.5		29.7	%		59.0		76.1	%		33.5
Other unregulated businesses		6.8		70.0	%		4.0		233.3	%		1.2

Total Unregulated		138.4		17.8	%		117.5		35.5	%		86.7

Financing/Other		(36.2	)	74.0	%		(20.8	)	-18.4	%		(25.5	)

Net income from continuing operations		298.2		8.9	%		273.8		20.3	%		227.5
Discontinued operations		31.9		6.7	%		29.9		27.7	%		23.4

Net income total	$	330.1		8.7	%	$	303.7		21.0	%	$	250.9

Earnings per Share—Basic (2)
Regulated Companies
Tampa Electric	$	1.12		-2.6	%	$	1.15		—		$	1.15
Peoples Gas System		.16		-5.9	%		.17		—			.17

Total Regulated		1.28		-3.0	%		1.32		—			1.32

Unregulated Companies
TECO Power Services		.22		10.0	%		.20		11.1	%		.18
TECO Transport		.14		-30.0	%		.20		-13.0	%		.23
TECO Coal		.50		13.6	%		.44		63.0	%		.27
Other unregulated businesses		.04		33.3	%		.03		200	%		.01

Total Unregulated		.90		3.4	%		.87		26.1	%		.69

Financing/Other		(.23	)	53.3	%		(.15	)	-25.0	%		(.20	)

EPS from continuing operations		1.95		-4.4	%		2.04		12.7	%		1.81
Discontinued operations		.20		-9.0	%		.22		22.2	%		.18

EPS Total	$	2.15		-4.9	%	$	2.26		13.6	%	$	1.99

(1)

Revenues for all periods have been adjusted to reflect the presentation of energy marketing related revenues on a net basis, the reclassification of TECO Coalbed Methane results to discontinued operations, and the reclassification of earnings from equity investments from Revenues to Other Income.

(2)

Beginning in 2001, segment net income was reported on a basis that included internally allocated financing costs. Prior period net income has been reclassified to reflect estimated internally allocated financing costs that would have been attributable to such prior periods. Internally allocated finance costs for 2002, 2001 and 2000 were at pretax rates of 7%, 7%, and 6.75%, respectively, based on the average investment in each subsidiary.

Tampa Electric—Electric Operations

Tampa Electric Results

Tampa Electric’s net income increased almost 12 percent in 2002, reflecting continued good residential and commercial customer growth, increased sales to phosphate customers and more favorable summer weather, partially offset by lower sales to other utilities and higher operations and maintenance expenses. The equity component of AFUDC, primarily from the Gannon to Bayside Units 1 and 2 repowering project, increased to $24.9 million, compared to $6.6 million in 2001.

Tampa Electric’s net income increased almost 7 percent in 2001, reflecting good customer growth, slightly higher residential and commercial per-customer energy usage, and a favorable customer mix, partially offset by higher operations, maintenance and depreciation expenses. In addition, AFUDC equity, primarily from the Gannon to Bayside Units 1 and 2 repowering project, increased to $6.6 million, compared with $1.6 million in 2000.

Net income increased in both 2002 and 2001 while operating income decreased due to higher AFUDC and lower interest expense which affect net income but not operating income.

Summary of Operating Results

(millions)	2002		Change		2001		Change		2000
Revenues	$	1,583.2	12.1	%	$	1,412.7	4.4	%	$	1,353.8
Other operating expenses		212.3	11.3	%		190.7	1.3	%		188.3
Maintenance		108.7	9.2	%		99.5	3.5	%		96.1
Depreciation		189.8	9.5	%		173.4	7.3	%		161.6
Taxes, other than income		112.3	7.2	%		104.8	6.2	%		98.7

Non-fuel operating expenses		623.1	9.6	%		568.4	4.4	%		544.7

Fuel		424.1	22.4	%		346.5	7.1	%		323.5
Purchased power		253.7	21.0	%		209.7	9.2	%		192.1

Total fuel expense		677.8	21.9	%		556.2	7.9	%		515.6

Total operating expenses	$	1,300.9	15.7	%	$	1,124.6	6.1	%	$	1,060.3

Operating income	$	282.3	-2.0	%	$	288.1	-1.8	%	$	293.5

Net income	$	171.8	11.6	%	$	154.0	6.6	%	$	144.5

Tampa Electric Operating Revenues

The economy in Tampa Electric’s service area continued to grow in 2002, aided by the region’s relatively low labor rates, attractive cost of living and affordable housing. The Tampa metropolitan area’s employment grew slightly in 2002, in spite of the continued U.S. economic slowdown. The local Tampa area unemployment rate rose to 4.2 percent in November 2002, up slightly from 4.0 percent in December 2001, compared to 5.0 percent for the State of Florida and 6.0 percent for the nation. The Tampa area, with its diverse service-based economy, did not experience the same drop in economic activities as those areas of the country with manufacturing-based economies. Tampa Electric experienced minimal impact by the slowdown in the tourist industry because the areas served are not as sensitive to changes in the tourist industry as some other areas of Florida.

Retail megawatt hour sales rose 5.6 percent in 2002, primarily from increased residential and commercial sales from higher numbers of customers, higher per-customer usage and warmer-than-normal summer weather. Electricity sales to the lower-margin industrial customers in the phosphate industry increased 18.2 percent in 2002 after a 10.9 percent decline in 2001. The phosphate industry saw increased demand and improved pricing worldwide which led to increased production in 2002. In 2001, the phosphate industry experienced a second year of a worldwide slowdown due to overcapacity and reduced usage that contributed to temporary facility closures during the year and the permanent closure of one phosphate processing facility. The company’s phosphate customers have indicated that they expect to vary production to maintain stable prices in 2003. Revenues from phosphate sales represented slightly less than 3 percent of base revenues in 2002 and 2001. Non-phosphate industrial sales increased in 2002 and 2001, primarily reflecting continued economic growth in the area.

Base rates for all customers were unchanged in 2002. However, Tampa Electric refunded $6.4 million to customers in 2002 related to 1999 revenues held subject to refund under agreements between the Florida Public Service Commission (FPSC), the Office of Public Counsel and Tampa Electric. Fuel-related revenues increased in 2002 under the FPSC approved fuel adjustment clause due to the recovery of a previous underrecovery of fuel expense in 2001 and increased customer usage. (See the Regulation section.)

Sales to other utilities for resale declined in 2002, primarily as a result of lower coal-fired generating unit availability due to more planned maintenance outages.

Based on expected growth from continued population increases and business expansion, Tampa Electric expects retail energy sales growth of approximately 2.5 percent annually over the next five years, with combined energy sales growth in the residential and commercial sectors of more than 3 percent annually. Tampa Electric’s forecasts indicate that summer retail demand growth is expected to average more than 100 megawatts per year for the next five years.

These growth projections assume continued local area economic growth even in the current national economic climate, normal weather and a continuation of the current market structure. (See the Investment Considerations section.)

Megawatt-Hour Sales

(thousands)	2002	Change		2001	Change		2000
Residential	8,046	6.0	%	7,594	3.1	%	7,369
Commercial	5,832	2.6	%	5,685	2.6	%	5,541
Industrial	2,612	12.2	%	2,329	-2.6	%	2,390
Other	1,435	4.9	%	1,368	2.2	%	1,338

Total retail	17,925	5.6	%	16,976	2.0	%	16,638
Sales for resale	1,084	-27.7	%	1,499	-41.5	%	2,564

Total energy sold	19,009	2.9	%	18,475	-3.8	%	19,202

Retail customers (average)	590.2	2.5	%	575.8	2.8	%	560.1

Tampa Electric Operating Expenses

Operating expenses increased almost 16 percent in 2002, reflecting higher fuel costs from an increased amount of power generated with higher-cost oil and natural gas, increased purchased power due to lower unit availability, higher Other operating expenses due to higher employee benefit costs and costs associated with a 7 percent reduction in the workforce, higher depreciation from normal plant additions to serve the growing customer base and the addition of a new peaking combustion turbine at the Polk Power Station in mid-2002, and accelerated depreciation associated with phasing out coal-related assets at the Gannon Power Station.

Operating expenses increased 6 percent in 2001, reflecting higher fuel costs from higher coal prices, increased purchased power costs due to lower unit availability, higher maintenance expenses associated with increased planned outages on coal-fired generating units, and higher depreciation from normal plant additions and accelerated depreciation associated with phasing out coal-related assets at the Gannon Power Station.

Non-fuel operations and maintenance expenses are expected to decrease in 2003 as a result of workforce reductions in 2002 and the repowering of the Gannon Station to natural gas with its lower manpower and maintenance requirements.

Depreciation expense is projected to increase in 2003, and in the future, from normal plant additions and the first phase of the Gannon to Bayside repowering project entering service in mid-2003. (See the Environmental Compliance section.)

Fuel costs increased 22 percent in 2002 despite lower coal costs, reflecting primarily increased generation with oil and natural gas due to lower coal unit availability. Natural gas and oil prices increased significantly in the second half of 2002. Average coal costs, on a cents-per-million Btu basis, decreased 6 percent in 2002 after a 7 percent increase in 2001. Purchased power expense increased in 2002 due to lower unit availability, primarily as a result of planned maintenance outages on base load generating units and unplanned outages during peak load periods. The effects of higher fuel and purchased power costs are also reflected in the higher operating revenues, as these costs are recovered through the fuel adjustment clause.

Nearly all of Tampa Electric’s own generation over the last three years has been produced from coal, and the fuel mix is expected to continue to be substantially comprised of coal until mid-year 2003, when the first of two repowered units at Bayside is scheduled to begin operating on natural gas. (See the Environmental Compliance section.) On a total energy supply basis, company generation accounted for 83 percent, 84 percent and 92 percent of the total system energy requirements in 2002, 2001 and 2000, respectively.

Peoples Gas System

PGS is the largest investor-owned gas distribution utility in Florida. It serves more than 281,000 customers in all of the major metropolitan areas of Florida.

PGS net income rose almost 5 percent in 2002. Contributing to these results were 4.1 percent customer growth, operations and maintenance expenses which were essentially unchanged from 2001, and higher volumes sold for off-system sales and higher volumes transported for power generation customers which more than offset the impact of mild winter weather.

Lower gas prices in the first half of 2002 made the use of natural gas more attractive for large customers than during the period of high prices in the first half of 2001. Gas prices increased in the second half of 2002 and into early 2003, but the differential between natural gas and other fuels has remained relatively constant, therefore, fuel switching is not expected to the same degree as was experienced in 2001.

PGS’ net income rose 6 percent in 2001 from 4 percent customer growth and increased gas transported for off-system sales. The high cost of gas early in 2001 had a negative impact on sales to larger interruptible and power generation customers, many of whom have the ability to switch to alternative fuels or to alter consumption patterns.

Historically the natural gas market in Florida has been underserved with the lowest market penetration in the southeastern U.S. PGS is expanding its gas distribution system into areas of Florida not previously served and within areas currently served.

Summary of Operating Results

(millions)	2002		Change		2001		Change		2000
Revenues	$	318.1	-9.9	%	$	352.9	12.2	%	$	314.5
Cost of gas sold		149.0	-20.1	%		186.4	18.7	%		157.0
Operating expenses		115.6	.2	%		115.4	4.4	%		110.5

Operating income	$	53.5	4.7	%	$	51.1	8.7	%	$	47.0

Net Income	$	24.2	4.8	%	$	23.1	6.0	%	$	21.8

Therms sold—by customer segment
Residential		60.2	2.4	%		58.8	2.1	%		57.6
Commercial		327.6	6.0	%		308.9	5.8	%		292.1
Industrial		423.8	22.3	%		346.5	-7.4	%		374.1
Power Generation		492.6	22.1	%		403.5	-3.6	%		418.6

Total		1,304.2	16.7	%		1,117.7	-2.2	%		1,142.4

Therms sold—by sales type
System Supply		332.5	13.8	%		292.2	-8.9	%		320.6
Transportation		971.7	17.7	%		825.5	.4	%		821.8

Total		1,304.2	16.7	%		1,117.7	-2.2	%		1,142.4

Customers (thousands)—average		277.5	4.1	%		266.6	4.1	%		256.2

Residential and commercial therm sales increased from more than 4 percent customer growth in 2002, more than offsetting mild winter weather. Therm sales to large industrial and power generation customers also increased, primarily from significantly lower gas prices in the first half of 2002.

Residential therm sales increased in 2001, the result of more than 4 percent customer growth and increased per-customer usage. Commercial therm sales also increased, primarily from increased per-customer use.

The actual cost of gas and upstream transportation purchased and resold to end-use customers is recovered through a Purchased Gas Adjustment (PGA) clause approved by the Florida Public Service Commission annually.

In Florida, natural gas service is unbundled for all non-residential customers, affording these customers the opportunity to purchase gas from any provider. The net result of this unbundling is a shift from commodity sales to transportation sales. Because commodity sales are included in operating revenues at the cost of the gas on a pass-through basis, there is no net financial impact to the company when a customer shifts to transportation-only sales. PGS markets its services to these customers through its “NaturalChoice” program. At year-end 2002, 9,500 customers had elected to take service under this program.

Operating expenses were essentially unchanged from 2001 levels. This achievement represents significant cost reduction efforts in all areas of the company to offset the effect of the mild winter weather.

In 2001, operation and maintenance expenses were essentially unchanged from 2000 levels, while depreciation expense increased 8 percent, in line with the increased capital expenditures made over the past several years to expand the system.

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.

In May 2002, Gulfstream Natural Gas Pipeline initiated service. This interstate pipeline starts in Mobile Bay, Alabama, crosses the Gulf of Mexico and comes ashore in Florida just south of Tampa. Gulfstream is the first new pipeline serving peninsular Florida since 1959. This pipeline increases gas transportation capacity into Florida by 50 percent. PGS entered into a service agreement for capacity in 2002, which increases in 2003 and 2004. The addition of the Gulfstream pipeline enhances reliability of service and helps to meet the capacity needs for PGS’ growing customer base.

PGS expects increases in sales volumes and corresponding revenues in 2003, and continued customer additions and related revenues from its expansion efforts throughout the state of Florida. These growth projections assume continued local economic growth, normal weather and other factors. (See the Investment Considerations section.)

TECO Power Services

Net income increased almost 27 percent in 2002 to $34.1 million from higher earnings from construction-related and loan agreements with Panda Energy International (Panda), a full year of ownership of the Frontera Power Station and higher capacity payments due to higher prices and generation at the Guatemalan generating units. The improved results were partially offset by a $5.8-million after-tax charge related to the proposed sale of TPS’ minority interest in generating assets in the Czech Republic, higher operations and maintenance expense, lower energy prices and sales from the Commonwealth Chesapeake Station and higher financing costs.

Net income increased 18 percent in 2001 to $26.9 million from higher earnings from the Hamakua, Commonwealth Chesapeake, and Guatemalan generating stations and higher returns on TPS’ investment through Panda in the Texas Independent Energy (TIE) projects. The improved operating performance was partially offset by weak results at the Frontera Station, which was acquired in March 2001, due to low power prices in the Texas market; increased financing costs; higher development costs; and a $6.1-million after-tax valuation reserve recognized in connection with the sale of TPS’ minority interest in EGI, which owns small generating projects in Central America.

Summary of Operating Results

(millions)	2002		Change		2001		Change		2000
Revenues	$	309.8	7.9	%	$	287.1	44.2	%	$	199.1

Operations, maintenance and A&G		73.1	8.9	%		67.1	24.3	%		54.0
Purchase power pass through		31.1	4.4	%		29.8	-1.0	%		30.1
Depreciation		28.1	-1.1	%		28.4	53.5	%		18.5
Taxes, other than income		8.4	15.1	%		7.3	135.5	%		3.1

Non-fuel operating expenses		140.7	6.1	%		132.6	25.4	%		105.7
Fuel		118.6	8.1	%		109.7	60.9	%		68.2

Total operating expense		259.3	7.0	%		242.3	39.3	%		173.9

Operating income	$	50.5	12.7	%	$	44.8	77.8	%	$	25.2

Net income	$	34.1	26.8	%	$	26.9	18.0	%	$	22.8

Generation
Megawatt hours (thousands)		3,411	10.4	%		3,089	89.2	%		1,633

Increases in energy generation reflect incremental new capacity coming into service either in phases or part year in 2000 and 2001 or acquired in 2001 with full year results reflected in 2002. Increases in operations, maintenance and administrative and general (A&G) expenses reflect the increased manpower and facilities and a full year of operations of the energy marketing and management group. Increases in these expenses over the three-year period reflect the increased size of the generating portfolio, which increased from three operating plants in January 2000 to five at Dec. 31, 2002.

Increases in income and operating expenses related to the Union and Gila River power stations in 2003 and 2004 are expected to be reflected in TPS’ financial results on a net basis assuming these facilities continue to be accounted for as unconsolidated affiliates. (See the Off-Balance Sheet Financing section.) However, operations, maintenance and A&G expenses are expected to increase because of increased staffing in the energy marketing and management group related to these two plants.

In 2003, TPS began negotiations to revise an equipment purchase contract. TPS may complete these negotiations by as early as the end of the first quarter 2003. If executed, the contract revision could result in a non-cash pretax charge of $12 to $24 million.

TPS Project Summary

Project	Location	Size MW	TPS Economic Interest		TPS Net Size MW	In Service/ Participation Date (1)
Operating:
Hardee Power Station	Florida	370	100	%	370	1/93, 5/00
Alborada Power Station	Guatemala	78	96	%	75	9/95
Empresa Eléctrica de Guatemala S.A.(EEGSA) (a distribution utility)	Guatemala		24	%		9/98(4)
San José Power Station	Guatemala	120	100	%	120	1/00
Hamakua Energy Project	Hawaii	60	50	%	30	8/00, 12/00
Frontera Power Station	Texas	477	100	%	477	5/00, 3/01(4)
Odessa and Guadalupe	Texas	2,000	(2	)	750	9/00, 8/01
Commonwealth Chesapeake Power Station	Virginia	315	100	%	315	9/00, 8/01

Sub-total operating		3,420			2,137

Under Construction:
Union	Arkansas	2,200	(3	)	1,650	1/03-6/03
Gila River	Arizona	2,145	(3	)	1,609	2/03-8/03

Sub-total construction		4,345			3,259

Total		7,765			5,396

Suspended:
Dell	Arkansas	599	100	%
McAdams	Mississippi	599	100	%

		1,198

(1)

Unless otherwise indicated, each date appearing in this column is an in-service date. When more than one in-service date appears, it indicates when different phases of the project went into operation. For projects under construction, a range of dates indicates when the first and last phases are expected to enter service under TECO Energy’s current plans.

(2)

Based on the effect of the preferred return, the effective economic interest is estimated at 75 percent of Panda’s 50-percent interest in these projects over the life of the projects.

(3)

Based on the effect of the preferred return, the effective economic interest is estimated at 75 percent over the life of the project.

(4)

Dates on which TPS acquired its economic interest in the project.

Construction Activities

In 2000, TPS focused its efforts on the development or acquisition of domestic energy projects. TPS has net ownership interest in almost 5,400 megawatts of projects either operating or under construction.

In September 2000, TPS invested $93 million in the form of a loan to Panda’s TIE, which are the Odessa and Guadalupe power stations. An additional $44 million was loaned to Panda in the first quarter of 2002 bringing the total investment to $137 million. The interest earned on the loan to TIE is reflected in 2002, 2001 and 2000 earnings.

These loans converted in accordance with their terms into an ownership interest on Jan. 3, 2003 which is to be accounted for under the equity method. The conversion gives TPS an opportunity to have an effective economic interest estimated at 75 percent of Panda’s 50-percent interest in these projects over the life of the projects. Based on information available from the other owners of these projects, these projects have realized lower than expected earnings and cash flows due to over capacity in the Texas market, uneconomic dispatch, and market design, and that trend is expected to continue in 2003. TPS is evaluating its options relative to its ownership position in these projects and is targeting to structure its interest in such a manner that it will cover its cash costs in 2003 and mitigate any impact on earnings.

In October 2000, TPS acquired two 599-megawatt, natural gas-fired, combined-cycle projects, Dell and McAdams, located in Arkansas and Mississippi, respectively. Construction commenced on these projects in 2001 but was suspended at the end of 2002 due to projected low energy prices in the markets that these plants were expected to serve. Interest will not be capitalized during the construction postponement period. The carrying costs associated with these suspended plants are expected to reduce TPS earnings in 2003. Market conditions will be monitored to determine when these plants will be completed. At the time of suspension, approximately $690 million had been invested in these plants. At the time of suspension, it was estimated that the construction cost to complete these projects would be approximately $100 million.

In November 2000, TPS entered into a 50/50 joint venture with Panda to build, own and operate the 2,200-megawatt Union Power Station in Arkansas and the 2,145-megawatt Gila River Power Station in Arizona. The partnership agreement calls for TPS to contribute all project equity and for TPS to earn a preferred return on the investment in these projects, which, over the projects’ life, could give TPS an effective economic interest estimated at 75 percent. Construction commenced on these projects in 2001. Each of these projects is expected to begin operation in four power blocks, beginning with the first 550-megawatt power block of Union which began operating in January 2003 and ending with the 540-megawatt final power block of Gila River expected in August of 2003. At Dec. 31, 2002, the TPS investment in these projects was $1.2 billion of project equity including the remaining $375 million equity bridge loan balance and $55 million already contributed related to the TECO Energy construction undertaking, described below. At Dec. 31, 2001, TPS had invested $624 million in these projects including $500 million of the equity bridge loan.

In December 2001, Enron Corp., a large energy trading and services company, filed for protection under the U.S. Bankruptcy Code. An Enron subsidiary, NEPCO, was serving as the construction contractor for the Union, Gila River, Dell and McAdams power stations. Enron guaranteed certain of NEPCO’s obligations under the construction contracts. The Union and Gila River power stations have financing in place with a syndicate of banks. The Dell and McAdams power stations are wholly owned by TPS and have not been financed.

As part of Enron’s centralized cash management procedure, Enron swept NEPCO’s cash before it was applied to pay project costs. Enron’s bankruptcy permitted the project lenders to stop funding construction costs for the Union and Gila River projects until the condition was cured or waived. TPS received approval from the project lenders on a plan that allowed funding to resume.

The plan involved TECO Energy replacing Enron as the guarantor of certain of NEPCO’s obligations under the construction contracts for these two projects, including payment by TECO Energy of any project cost overruns (estimated at $62 million remaining at Dec. 31, 2002, against which TECO Energy could offset the unused construction contingency amount remaining after completion of construction) and guaranteeing the completion of construction. The plan also provided for TECO Energy to replace the letter of credit furnished by Enron that had been drawn upon and acceleration of project cash commitments to mid-year 2002, resulting in TECO Energy’s total investment essentially being complete by the end of 2002 rather than mid-2003 as originally planned.

Under a series of agreements with TECO Panda Generating Co. (TPGC), NEPCO continued construction and engineering of all four plants until SNC Lavalin Constructors Inc., a large Canadian engineering and construction firm, replaced it as the contractor in May 2002. SNC Lavalin hired essentially all of NEPCO’s management and staff, and construction continued without interruption. The agreements with SNC Lavalin provide for the projects to be completed on a cost-plus-fee basis, with the fee portion at-risk until the projects are completed.

In February 2002, the TPS and Panda affiliates that comprise the joint venture that owns the Union and Gila River projects entered into a purchase arrangement for TPS to purchase and Panda to sell Panda’s interest in the joint venture in 2007 for $60 million. Panda has the right to cancel the purchase arrangement by paying TPS $20 million, or a lesser amount under certain circumstances. The purchase arrangement could result in TPS’ purchase of the interest prior to 2007 if Panda defaults on a bank loan made to Panda using the purchase arrangement as collateral or if TECO Energy permits its debt-to-capital ratio to exceed 65.0 percent, permits its EBITDA/interest ratio to fall below 1.5 times or it defaults on the payment of indebtedness in excess of $50 million. TECO Energy’s debt-to-capital ratio at Dec. 31, 2002 was 55.9 percent and its EBITDA/interest ratio was 3.6 times.

In March 2001, TPS acquired the Frontera Power Station located near McAllen, Texas. This 477-megawatt, natural gas-fired, combined-cycle plant, began combined-cycle operation in May 2000 and has a 150-megawatt transmission connection to the Federal Electricity Commission of Mexico. In the second and third quarters of 2002, the facility sold energy and ancillary services to the Electric Reliability Council of Texas (ERCOT). During the fourth quarter the facility provided reliability-must-run (RMR) services under contract to ERCOT. Since the RMR contract was not renewed for the first quarter of 2003, the plant was shut down for scheduled maintenance. The first quarter is expected to have lower opportunities than other quarters for sales to ERCOT, Mexico or other customers due to weather.

In February 1999, TPS invested in EGI, a company with energy interests in Latin America. In the first quarter 2001, TPS recognized a $6.1-million after-tax charge as part of the sale of its interest in EGI. TPS no longer has any ownership interest in EGI.

Energy 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 United States, 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 have combined with aggressive plans by the independent power industry to add merchant power facilities to cause excess generating capacity that is either being built or has come on line in many markets. This excess supply

has depressed both spot and forward wholesale power prices. Based on current forward curve prices for 2003, the combined returns for the Union and Gila River power stations are expected to be below earnings break-even, but are anticipated to be close to covering cash costs. If cash costs are not covered, the non-recourse project finance lenders are required to fund the payments of these costs with additional non-recourse debt up to $80 million through a debt-service reserve. The forward curve prices represent the market price for on-peak energy that a seller would expect to receive if future energy was sold today. The forward curve for electricity prices reflects the price for energy that is delivered on a standard schedule. Because TPS’ assets can be dispatched with some flexibility and sales of ancillary services are possible, the forward curve price may understate the realized price or profit margin.

Studies by numerous outside groups, such as Cambridge Energy Research Associates, Standard & Poor’s and others, present conflicting outlooks on power price improvement. Some experts indicate that 2003 should be the low point for power prices while others indicate that power prices may remain low beyond 2004. Continued low power prices for the output from TPS’ merchant plants in 2004 would decrease net income at TPS from 2003 levels, and could require cash payments to cover any fixed costs of the plants not covered by the project debt-service reserves or cash generated at the projects.

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 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 so as to know the margins for such sales at the time of commitment. These sales usually do not include the value for capacity payments, ancillary services, dispatchability and the premium associated with owning physical assets. These incremental value components are often captured in the spot market at the time of physical sales or through more structured transactions.

In 2001, TPS activated its TECO EnergySource (TES) subsidiary to enter into power marketing and fuel procurement transactions for the longer-term contracts. Initially, TPS retained power marketers, such as Aquila for the Union and Gila River power stations, to market the output planned for the spot market. Aquila has decided to exit the power marketing business and TPS intends to assume full responsibility for the output marketing and fuel procurement transactions. TES is actively seeking both short- and long-term contracts with purchasers for the output from the Union and Gila River power stations and the Frontera Power Station.

TES is contracting to purchase or supply electricity and natural gas, primarily at specified delivery points and specified future dates (i.e., fixed-price forward sales and purchase contracts). In some cases TES is utilizing financial instruments such as futures and contracts traded on the NYMEX and swaps and other types of financial instruments traded in the over-the-counter markets to manage its exposure to electricity and natural gas price fluctuations.

The use of these types of contracts allows TPS to manage and hedge its contractual commitments and to reduce its exposure relative to the volatility of spot market prices. TPS’ and TES’ use of futures, options, swaps or other financial instruments was minimal in 2002 due to the low volume of energy sales.

TPS normally balances its fixed-price physical and financial fuel purchase and energy sales contracts in terms of contract volumes and the timing of performance and delivery obligations. Net open positions may exist for short periods due to the origination of new transactions. When net open positions exist, TPS will be exposed to fluctuating market prices. All fuel purchase and energy sales contracts and open positions are monitored closely by the TECO Energy risk management function, which is independent of the TPS’ energy management group.

In addition to price risk, credit risk is inherent in TPS’ energy risk management activities. The marketing business may be exposed to counterparty credit risk from a counterparty not fulfilling its obligations. Credit policies and procedures, administered by TECO Energy, attempt to limit overall credit risk. The credit procedures include a thorough review of potential counterparties’ financial position, collateral requirements under certain circumstances, monitoring net exposure to each counterparty and the use of standardized agreements.

TPS is currently not required to post cash collateral for fuel purchases or as a counterparty for energy sales. In the event of a TECO Energy credit downgrade to non-investment grade, TPS would be required to post cash collateral for energy management activities. Dec. 31, 2002 positions would require the posting of $9.3 million of cash collateral in the event of a downgrade.

Significant factors that could influence results at TPS include construction of its new projects on schedule and on budget, energy prices in its markets, the ability to earn a premium above forward curve prices, weather, domestic economic conditions and commodity price changes. (See the Investment Considerations section.)

TECO Transport

Net income declined 24 percent in 2002 to $21.0 million, compared with $27.6 million in 2001. TECO Transport’s results reflect continued weakness in the U.S. economy as low levels of imported raw materials reduced northbound river shipments and drove pricing lower for all river shipments. These conditions also reduced volumes of petroleum coke and steel-related product volumes through the transfer terminal. These conditions combined to more than offset increased ocean-going phosphate shipments and lower repair and fuel costs.

Net income declined 6 percent in 2001. Increased phosphate and other product shipments, higher revenue from outside services at TECO Barge Line, and lower fuel prices were more than offset by lower U.S. government grain program shipments, higher costs primarily related to depreciation, and lower shipments of steel-related products handled by TECO Bulk Terminal. Results for 2000 included an after-tax gain of approximately $1.5 million associated with the disposition of an ocean-going asset.

After a late start to U.S. government grain shipments in 2002, volume and pricing improved in the fourth quarter. The pattern of an intense but short annual period for moving grain shipments in the fall and winter is expected to repeat in 2003. Northbound river shipments of steel-related raw materials are expected to improve in 2003 as the U.S. economy improves. Southbound river shipments of grain products are expected to increase slightly in 2003, with a small increase in pricing expected. Even with the expected price increase, grain freight rates are expected to remain below historical levels, which will impact the pricing for all commodities moved on the rivers. In the meantime, TECO Transport expects to move increased volumes of fertilizers and petroleum coke northbound on the river system.

The phosphate fertilizer industry experienced an increase in worldwide demand in 2002 after a period of reduced demand in 2001 and 2000, which resulted in increased shipments of raw phosphate rock between Tampa and Louisiana. The outlook for TECO Ocean Shipping is for a slight increase in phosphate demand in 2003. Lower shipments for Tampa Electric and higher fuel and employee-related health care and pension costs are expected in 2003.

TECO Transport expects to continue diversifying into new markets and cargoes. Future growth at TECO Transport is dependent on improved pricing, higher asset utilization, and asset additions at both the river and ocean-going businesses. Significant factors that could influence results include weather, bulk commodity prices, fuel prices and domestic and international economic conditions. (See the Investment Considerations section.)

TECO Coal

Net income increased 30 percent in 2002, to $76.5 million, driven primarily by better margins and higher synthetic fuel (synfuel) production and sales and the resulting higher Section 29 tax credits. Production of synthetic fuel at TECO Coal qualifies for Section 29 tax credits for non-conventional fuel production.

Synfuel production increased to 3.8 million tons in 2002 compared with 3.2 million tons and 1.9 million tons in 2001 and 2000, respectively. The net benefit increased to approximately $77 million in 2002 compared with $58 million in 2001 and approximately $30 million in 2000. Synfuel production displaced some of the conventional coal production in all years.

Net income at TECO Coal increased 76 percent in 2001, driven primarily by better margins and higher synfuel production, increased coal production from Perry County Coal, Inc.’s mining facilities acquired in late 2000, and higher metallurgical coal prices in the second half of the year. 2001 was the first full year of production for the synfuel production facilities which entered service late in the second quarter of 2000.

In 2002, coal sales, including synfuel, decreased to 9.3 million tons from 10.1 million tons in 2001 due to soft market conditions. In 2003, total coal sales are expected to increase slightly due to more normal supply and demand in the market. Synfuel volumes are expected to increase to more than 5 million tons and conventional coal production is expected to decline to offset the higher synfuel production in 2003. In 2003, TECO Coal intends to sell the majority of its interest in the synfuel production facilities, but retain responsibility for operating the facilities. (See the Strategy and Outlook section.)

Metallurgical coal contracts, which normally renew in the first quarter of the year, resulted in lower prices in 2002 after a strong pricing environment in 2001. Prices are expected to remain near current levels in 2003. Steam coal pricing declined industry wide in the first quarter of 2002, due to high utility inventory levels as a result of the mild winter weather. TECO Coal, however, contracts much of its steam coal production for the coming year late in the preceding year and was less affected by the price declines than those companies that sell a higher percentage in the spot markets. Later in the year, after inventories were reduced to more normal levels, coal prices strengthened and contract renewals for 2003 were achieved at prices only slightly lower than 2002 levels.

In January 2000, TECO Coal purchased synfuel facilities from Headwaters Technologies, Inc. The facilities were relocated to the company’s Premier Elkhorn and Clintwood Elkhorn mines in Kentucky, and were producing by the second quarter of 2000. These facilities produce synfuel from coal, coal fines and waste coal using a technology licensed from Headwaters. The facilities were subsequently sited at all three of TECO Coal’s complexes.

TECO Coal has received private letter rulings from the Internal Revenue Service regarding the production of synfuel from its facilities. The private letter rulings confirm that the facilities are located appropriately and produce a qualified fuel eligible for Section 29 tax credits which are available for the production of such non-conventional fuels through 2007.

Significant factors that could influence TECO Coal’s results include weather, general economic conditions, commodity price changes, continued generation of Section 29 tax credits, the sale of interest in the synfuel production facilities, the ability to use Section 29 tax credits and changes in laws, regulations or administration. (See the Investment Considerations section.)

Other Unregulated Companies

In 2002, net income for the other unregulated companies increased 70 percent to $6.8 million driven primarily by the full-year results of Prior Energy Corp., TECO Energy’s end-use gas marketing company acquired in November 2001. In 2001, net income increased due to a full year of results from BCH Mechanical, which was acquired in September 2000.

Other unregulated companies include TECO Energy Services (formerly TECO BGA, Inc., and BCH Mechanical, Inc. and its affiliated companies), TECO Gas Services, TECO Properties, Prior Energy Corp., TECO Propane Ventures (TPV), TECO Partners and TECO Investments. Except for TECO Investments, these operating companies are organized under TECO Solutions, which was formed to offer customers (primarily in Florida) a comprehensive package of energy services and products including energy-efficient engineering and construction and gas management services.

In November 2001, TECO Solutions acquired Prior Energy Corp., a leading natural gas management company. Serving customers throughout the Southeast, Prior Energy handles all facets of natural gas energy management services for large industrial, power generation utility, municipal and other governmental agency customers, including natural gas acquisition and supply management, transportation management, asset management and consulting services.

TPV holds the company’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.

Liquidity, Capital Resources

Sources of cash for TECO Energy and its operating companies in 2002 totaled $3.4 billion, including operating cash flows of $656 million and proceeds from the sale of debt and equity securities of $2.8 billion. Cash was used to fund $1.7 billion of capital spending (net of $103 million from asset sales), debt maturities of $788 million and refinancings of $162 million, net reduction of short-term debt of $278 million and dividends to common shareholders of $216 million. TECO Energy began the year with $109 million in cash and cash equivalents and ended the year with $411 million in cash and cash equivalents and $460 million of unused capacity available under the bank credit facilities at TECO Energy and Tampa Electric. The increased year-end cash position was attributable in part to the conversion of the TECO Energy bank credit facility to a term loan and other cash generating activities.

TECO Energy met 2001 cash needs with a mix of internally generated funds, short- and long-term borrowings and proceeds from the sale of equity. Cash from operations was $503 million, and net cash from financing was $614 million after common dividends of $184 million. Capital spending totaled $1.1 billion in 2001.

In light of the accelerated equity commitments for the Union and Gila River projects under the bank financing plan, an unexpected deterioration in the bank project finance market which caused a planned financing to not materialize, and the capital requirements for committed regulated and unregulated projects, TECO Energy took several steps to strengthen its balance sheet in 2002 and provide cash for its construction program. In January 2002, the company reduced its previous capital expenditure forecast for 2002 through 2004 by about $700 million, primarily by delaying indefinitely generation projects that were not yet under construction for TPS and Tampa Electric, including the Bayside Units 3 and 4 repowering projects announced in the fall of 2001.

In September 2002, TECO Energy announced additional plans to meet its 2003 construction commitments without raising incremental debt, identifying a total amount required of $900 million. By the end of 2002, TECO Energy had completed 70 percent of its $900 million target by: 1) reducing by $250 million capital spending projections (which included amounts higher than earlier estimates); 2) selling the TECO Coalbed Methane gas assets for $140 million, with $42 million received in December and the remainder received in January 2003; 3) realizing $55 million of cash from repatriation and additional cash from non-recourse-financing of the Guatemalan generating assets; and 4) raising $207 million from the sale of common equity in October.

Tampa Electric has signed a letter of intent for the sale of its gasifier unit, and TECO Coal is continuing discussions with potential buyers of interests in its synthetic fuel production facilities. Completion of these activities, which will complete the 2003 funding plan, is expected late in the first quarter or early in the second quarter of 2003.

Estimated cash needs for 2003 include capital spending of $727 million for normal renewal and replacement capital as well as project commitments of Tampa Electric and TPS, including $375 million related to payment of the Union and Gila River projects equity bridge loan. (See the Summary of Contractual Obligations section.) Long-term debt maturities of $127 million are due in 2003, and a bank term loan of $350 million matures in November. TECO Energy expects to rely on cash on hand and internally generated cash from operations and from asset sales to fund these cash needs and the payment of dividends to shareholders. (See the Bank Credit Facilities and Covenants in Financing Agreements sections.) Based on its cash flow forecasts, TECO Energy expects to have at least $600 million of cash and capacity under the bank credit facilities at the end of the first, second and third quarters of 2003 and, if it renews its bank facilities in full, at the end of 2003.

TECO Energy has identified in this Management’s Discussion & Analysis (including in Investment Considerations), several factors that could cause its operating cash flow to be lower than forecasted. One of these factors is the margins it may realize for production from its merchant power facilities. Because of TECO Energy’s expansion in the merchant power business, its cash flow has become increasingly dependent upon power margins.

TECO Energy has not made a contribution to its defined benefit pension plan since the 1995 plan year because investment returns have been more than sufficient to cover liability growth. Negative stock market returns over the past three years have reduced the over-funding of the defined benefit plan. Based on plan asset values at Jan. 1, 2003, it is estimated that TECO Energy will be required to make a $15 million contribution to its defined benefit plan in September 2004. (See Note K to the Consolidated Financial Statements.)

Bank Credit Facilities

At Dec. 31, 2002, TECO Energy had a bank credit facility of $350 million, and Tampa Electric had a bank credit facility of $300 million, with maturity dates of November 2004 and November 2003, respectively. Both were undrawn at Dec. 31, 2002, except for outstanding letters of credit under the TECO Energy facility. In November 2002, TECO Energy converted another $350 million bank credit line then in effect into a one-year term loan due November 2003. TECO Energy expects to have discussions with the bank-lending group with the objective of renewing the facility before the loan matures.

The TECO Energy bank credit facility maturing November 2004 includes a $250 million sublimit for letters of credit capacity. At Dec. 31, 2002, $180 million of letters of credit were outstanding against that line, primarily related to the construction of the Union and Gila River power stations. These letters of credit of $62 million and $88 million for Union and Gila River, respectively, were replacements for the letters of credit posted by Enron and drawn by the TPS/Panda joint venture following Enron’s bankruptcy filing. In addition, at Dec. 31, 2002, TECO Energy and its subsidiaries had $5 million of letters of credit outside of its bank credit line facility outstanding. (See the Covenants in Financing Agreements section.)

The Tampa Electric bank credit facility requires commitment fees of 15 basis points, and drawn amounts are charged interest at LIBOR plus 85-97.5 basis points at current credit ratings. The TECO Energy credit facility requires commitment fees of 15-20 basis points and drawn amounts incur interest expense at LIBOR plus 35-60 basis points at current credit ratings. TECO Energy expects that the cost of its facility will increase upon renewal.

The September 2002 downgrade by Standard & Poor’s Ratings Service (S&P) of TECO Energy’s commercial paper program to A-3 eliminated TECO Energy’s access to the commercial paper market. Tampa Electric continues to have access to the commercial paper market with its A2/P1/F2 rated commercial paper program and had $11 million of commercial paper outstanding at Dec. 31, 2002. The lack of access to the commercial paper market has caused TECO Energy to utilize its bank credit facilities for short-term borrowing needs.

Credit Ratings/Senior Unsecured Debt

	Fitch	Moody’s	Standard & Poor’s
Tampa Electric	A-	A2	BBB
TECO Finance / TECO Energy	BBB	Baa2	BBB-

In September 2002, Moody’s Investor Services, Inc. (Moody’s), S&P and Fitch Investor Services, Inc. (Fitch). lowered the ratings on the senior unsecured debt securities of TECO Energy, TECO Finance and Tampa Electric. The outlook assigned to TECO Energy by Moody’s and S&P is negative while the outlook assigned by Fitch is stable. The ratings actions were attributed to increased debt levels and the changing risk profile associated with the expansion of TECO Energy’s investment in merchant generation facilities through TPS, as well as the required capital outlays of Tampa Electric, the outlook for low power prices in the merchant energy sector and the negative impacts on earnings and cash flow, and the additional risks and obligations undertaken by TECO Energy with respect to the Union and Gila River power stations. These downgrades followed downgrades in 2001 and 2000 by all of the rating agencies due to the changing risk profile of TECO Energy related to the increased emphasis on merchant power.

These downgrades and any future downgrades may affect TECO Energy’s ability to borrow and may increase financing costs, which may decrease earnings. TECO Energy’s interest expense is likely to increase when maturing debt is replaced with new debt with higher interest rates due to the lower credit ratings.

Summary of Contractual Obligations

The following table lists the obligations of TECO Energy and its subsidiaries for cash payments to repay debt, lease payments and unconditional commitments related to capital expenditures. This table does not include contingent obligations discussed in the following table.

Contractual Obligations

	Payments Due by Period
(millions)	Total		2003		2004		2005-2007			After 2007
Long-term debt	$	3,426.1	$	101.8	$	31.9	$	1,048.9		$	2,243.5
Capital lease obligation		25.3		25.3		—		—			—
Operating leases/rentals		230.4		27.8		26.9		63.0			112.7
Unconditional purchase obligations/commitments (1)		563.0		461.6		41.4		60.0	(3)		—
Other long-term obligations (2)		649.1		—		—		449.1			200.0

Total contractual obligations	$	4,893.9	$	616.5	$	100.2	$	1,621.0		$	2,556.2

(1)

Includes the expected repayment of $375 million on the TECO Energy guaranteed equity bridge loan at TPS for the construction of the Union and Gila River power stations.

(2)

Includes the expected redemption of company preferred securities held as assets of TECO Capital Trusts I and II.

(3)

TPS’ obligation to purchase Panda’s interest in the Union and Gila River power stations in 2007, unless Panda buys out that purchase agreement in advance. (See the TECO Power Services—Construction Activities section.)

Summary of Contingent Obligations

The following table summarizes the letters of credit and guarantees outstanding that are not included in the Summary of Contractual Obligations table above and not otherwise included in the company’s Consolidated Financial Statements.

	Commitment Expiration
(millions)	Total (2)		2003		2004		2005-2007		After 2007
Letters of Credit (1)	$	185.0	$	128.0	$	27.1	$	—	$	29.9
Guarantees:
Debt related		23.7		—		—		—		23.7
Construction undertaking (3)		60.0		60.0		—		—		—

(1)

Expected final expiration date with annual renewals.

(2)

Expected maximum exposure.

(3)

The construction undertaking of $60 million reflected in the table represents the estimated maximum probable exposure associated with completing construction of the Union and Gila River power stations if actual costs exceed current estimates and in-service dates are delayed beyond current estimates. This contingent obligation estimate is net of retainage letters of credit posted for these projects. This estimate will decline rapidly as construction progresses and units are brought into service. (See the TECO Power Services–Construction Activities section.)

Covenants in Financing Agreements

In order to utilize their respective bank credit facilities, TECO Energy and Tampa Electric must meet certain financial tests. TECO Energy’s credit facilities and the financing arrangements of TPS’ Union and Gila River power stations require that at each quarter-end TECO Energy’s debt-to-capital ratio, as defined in the applicable agreements, not exceed 65%. Under Tampa Electric’s 364-day credit facility, renewed in November 2002, its debt-to-capital ratio may not exceed 60 percent at the end of the applicable quarter and its earnings before interest, taxes, depreciation and amortization (EBITDA) to interest coverage ratio (as defined in the agreement) can not be less than 2.5 times. Certain long-term debt at PGS contains a prohibition on the incurrence of funded debt if Tampa Electric’s debt-to-capital ratio, as defined in the applicable agreement, exceeds 65%. The PGS debt also contains a Tampa Electric interest coverage requirement, as defined in the applicable agreement, of 2.0 times or greater for four consecutive quarters, and certain TPS financing arrangements require a TECO Energy consolidated interest coverage, as defined in the applicable agreement, equal to or exceeding 3.0 times for the twelve-month period ended each quarter. At Dec. 31, 2002, TECO Energy’s and Tampa Electric’s debt-to-capital ratios, as applicable,

were 55.9 percent and 43.9 percent, respectively, and interest coverage, as applicable, was 3.6 times and 7.8 times, respectively. TECO Energy expects that renewal of its facility will require covenants similar to Tampa Electric’s.

The TECO Energy guarantees of the Union and Gila River power stations equity bridge financing, equity contribution agreement and construction undertaking require that TECO Energy maintain senior unsecured credit ratings of not less than BBB and Baa3 or BBB- and Baa2. TECO Energy’s current ratings are at the minimum required level. A further downgrade from either S&P or Moody’s would trigger a failure to meet that requirement, thereby requiring the delivery of letters of credit, which the company currently estimates could approximate $450 million, to secure the obligations. In the event of a downgrade, under the terms of the construction contract guarantees, TECO Energy is required to deliver letters of credit in an amount equal to the full construction contract price and any change orders and cost overruns or such lesser amount satisfactory to the majority of the lenders for the Gila River and Union power stations. TECO Energy believes that the amounts required would be based on the estimated amounts reasonably necessary to cover the remaining payment and performance obligations under the construction contracts. As of January 2002, when documenting the construction contract guarantees with the lenders for the Gila River and Union power projects, the maximum amount necessary to cover the payment and performance obligations of the contractor was estimated to be approximately $310 million, net of approximately $150 million in letters of credit previously issued to the lenders as security for the projects. Based on the construction status as of Dec. 31, 2002, TECO Energy estimates the maximum amount necessary to cover the payment and performance obligations of the contractor to be approximately $60 million, net of the approximately $150 million in letters of credit previously issued as security. This $60 million is included in the $450 million amount referenced above. The amount of the letters of credit that would be required to be delivered declines as equity is contributed to the projects, the bridge loan is repaid and the levels of construction completion increase.

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. The covenants apply only if either the notes are rated non-investment grade by either S&P or Moody’s or the notes are rated below the levels required by the equity bridge loan and Union and Gila River construction undertaking while those obligations are outstanding. If these covenants become applicable, the coverage requirement would restrict TECO Energy from paying dividends or distributions or making certain investments unless cumulative EBITDA to interest coverage is at least 1.7 times.

Capital Investments

	Actual		Forecast
$ (millions)	2002		2003		2004		2005-2007		2003-2007 Total
Florida Operations	$	662	$	272	$	266	$	725	$	1,263
Independent Power		1,027		424		25		75		524
Transportation		25		15		21		61		97
Other		50		16		23		55		94

Total	$	1,764	$	727	$	335	$	916	$	1,978

TECO Energy’s 2002 capital investments of $1,764 million (without reduction for asset sale proceeds of $103 million) included $597 million for Tampa Electric (excluding $35 million of AFUDC), $54 million for PGS and $11 million for the unregulated Florida operations. Tampa Electric’s electric division capital investments in 2002 were $169 million for equipment and facilities to meet its growing customer base and generating equipment maintenance, $343 million for the repowering and conversion of the coal-fired Gannon Station to the natural gas-fired Bayside Station (see the Environmental Compliance section), and $85 million for the 180 MW Polk Unit 3 peaking combustion turbine and future generation expansion requirements. Capital expenditures for PGS were approximately $39 million for system expansion and approximately $12 million for maintenance of the existing system. TECO Transport invested $25 million in 2002 for river barge replacements and capitalized maintenance of ocean-going vessels. TECO Coal’s capital expenditures included $48 million for the expansion of production at Perry County and Clintwood as well as normal equipment replacements. TPS’ capital investments totaled $1,027 million, primarily related to the Union, Gila River, Dell and McAdams power stations. This $1,027 million includes $672 million classified as Other Non-Current Investments, shown as notes receivable from TPGC (see the Transactions With Related and Certain Other Parties section), which represents TECO Energy’s equity contributions for the Union and Gila River projects. The Union and Gila River contributions are initially made in the form of loans to TECO-Panda Generating Company (TPGC) and become equity as the units’ specified phases come into service.

TPS expenditures represent the equity funding of project costs and exclude amounts funded by non-recourse project financing for the Union and Gila River power stations, which amounted to $627 million in 2002. (See TECO Power Services—Construction Activity and Item 3. Legal Proceedings sections.)

Asset sale proceeds of $103 million in 2002 included proceeds from the sale of TECO Coalbed Methane’s assets, real estate sales, and TECO Transport’s sale and lease-back of vessels and barges accounted for as an operating lease.

TECO Energy estimates capital spending for ongoing operations, without reduction for proceeds from asset sales, to be $727 million for 2003, $335 million for 2004 and $916 million during the 2005-2007 period. TECO Energy’s funding plan for these expenditures includes the asset sales described in the Strategy and Outlook section.

For 2003, Tampa Electric’s electric division expects to spend $232 million, consisting of $78 million for the repowering project at the Gannon Station and $154 million to support system growth and generation reliability. At the end of 2002, Tampa Electric had outstanding commitments of about $119 million for the Gannon Power Station repowering project. Tampa Electric’s total capital expenditures over the 2004-2007 period are projected to be $841 million, including $67 million for the repowering project and $141 million for compliance with the Environmental Consent Decree. (See the Environmental Compliance section.)

Capital expenditures for PGS are expected to be about $40 million in 2003 and $160 million during the 2004-2007 period. Included in these amounts are approximately $25 million annually for projects associated with customer growth and system expansion. The remainder represents capital expenditures for ongoing renewal, replacement and system safety.

TPS expects to invest $424 million in 2003 primarily for the completion of the Union and Gila River power stations. These investments include $375 million to repay the outstanding amounts due under the project company’s equity bridge loan guaranteed by TECO Energy, which is expected to be repaid in three $125 million installments in the second, third and fourth quarters of 2003.

The other unregulated companies expect to invest $31 million in 2003 and $160 million during the 2004-2007 period. Included in these amounts is normal renewal and replacement capital including coal mining equipment.

Financing Activity

TECO Energy’s 2002 year-end capital structure, excluding the effect of unearned compensation, was 53.7 percent debt, 9.1 percent company preferred securities and 37.2 percent common equity. TPS typically finances its power projects with non-recourse project debt. Excluding this non-recourse debt of $232.4 million, the year-end capital structure was 52.1 percent debt, 9.4 percent company preferred securities and 38.5 percent common equity.

In 2002, TECO Energy was active in the debt and equity capital markets raising $1 billion through the sale of equity or equity-linked securities and issuing $1.8 billion of debt to refinance $788 million of maturing debt, to refinance $162 million of higher-cost debt, to reduce short-term borrowing by $278 million and to fund capital investments at the operating companies. These transactions and financings in 2002 and 2001 are detailed in the following table.



Date	Security	Company	Net Proceeds (millions)	Coupon	Use

Dec. 2002	7-year non-recourse bank loan	TECO Power Services	$30	6%	Refinance Alborada Power Station and general corporate purposes

Nov. 2002	5-year notes	TECO Energy	$352	10.5%	Repay short- and long-term debt, and general corporate purposes

Oct. 2002	Common Equity	TECO Energy	$207	—	Repay short-term debt

Aug. 2002	5-year notes	Tampa Electric	$149	5.375%	Repay maturing long- and short-term debt, and general corporate purposes

Aug. 2002	10-year notes	Tampa Electric	$394	6.375%	Repay maturing long- and short-term debt, and general corporate purposes

Jun. 2002	Pollution control bonds	Tampa Electric	$61	5.1%	Refinance higher cost debt

Jun. 2002	Pollution control bonds	Tampa Electric	$86	5.5%	Refinance higher cost debt

Jun. 2002	Common Equity	TECO Energy	$346	—	Repay short-term debt, and general corporate purposes

May 2002	5-year notes	TECO Energy	$297	6.125%	Repay maturing short-term debt, and general corporate purposes

May 2002	10-year notes	TECO Energy	$397	7.0%	Repay maturing short-term debt, and general corporate purposes

Jan. 2002	Mandatorily Convertible equity units	TECO Energy	$436	9.5%	Repay short-term debt, and general corporate purposes

Oct. 2001	Common Equity	TECO Energy	$93	—	General corporate purposes

Sept. 2001	10-year notes	TECO Energy	$206	7.2%	Repay maturing debt, and general corporate purposes

Jun. 2001	11-year notes	Tampa Electric	$247	6.875%	Repay long- and short-term debt, and general corporate purposes

May 2001	1-year notes	TECO Energy	$399	Variable	Repay short-term debt

May 2001	10-year notes	TECO Energy	$396	7.2%	Repay short-term debt, and general corporate purposes

Apr. 2001	6-year notes	TECO Transport	$111	5.0%	Convert floating rate debt to fixed rate debt

Mar. 2001	Common Equity	TECO Energy	$232	—	Repay short-term debt, and general corporate purposes

Off-Balance Sheet Financing

Unconsolidated affiliates in which TPS has a 50% ownership interest or less have non-recourse project debt balances as follows at Dec. 31, 2002. This debt is recourse only to the unconsolidated affiliate, and TECO Energy has no debt payment obligations with respect to these financings. Although TECO Energy is not obligated on the debt, TECO Energy’s equity interest in those unconsolidated affiliates and its commitments with respect to those power projects are at risk if those projects are not successfully developed.

Affiliate	Affiliate Debt Balance (millions)		TPS Ownership Interest
Union & Gila River	$	1,175	50	%
EEGSA	$	200	24	%
Hamakua	$	86	50	%

The equity method of accounting is used to account for investments in partnership and corporate entities in which TECO Energy or its subsidiary companies do not have either a majority ownership or exercise control. On Jan. 17, 2003, the Financial Accounting Standards Board issued FASB Interpretation (FIN) No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51, which requires a new approach in determining if a reporting entity should consolidate certain legal entities, including partnerships, limited liability companies, or trusts, among others, collectively defined as variable interest entities or VIEs. Based on a preliminary review, TECO Energy believes it is reasonably possible that FIN 46 may impact the accounting for certain unconsolidated affiliates. (See the Other Accounting Standards – Variable Interest Entities section.)

In June 2001, TPS and its joint venture partner, Panda, closed on a $2.175 billion syndicated bank financing for the construction of the Union and Gila River power stations. The financing includes $1.675 billion in five-year non-recourse debt (including facilities for letters of credit) and $500 million in equity bridge loans guaranteed by TECO Energy of which $125 million was repaid in 2002. Pricing for the non-recourse segment is 162.5 basis points over LIBOR during the construction period and increases to 175 basis points for year one of operation and 200 basis points for years two and three.

The TPGC debt balance is expected to reach $1.4 billion upon completion of construction of the Union and Gila River power stations in 2003.

In addition, TECO Energy has other debt-related items totaling $23.7 million. These facilities are not included in liabilities on TECO Energy’s consolidated balance sheet, but do represent payment obligations of TECO Energy.

In March 2001, TPS converted the third-party construction financing for the Hamakua Power Station into a synthetic equipment operating lease with a term of five years. The lessor is an unaffiliated entity.

Critical Accounting Policies and Estimates

The following accounting policies are considered critical in the view of management. These critical accounting policies require that critical estimates be made based on the assumptions and judgment of management. The preparation of consolidated financial statements requires management to make various estimates and assumptions that affect revenues, expenses, assets, liabilities and disclosure of contingencies. The policies and estimates identified below are the more significant accounting policies and estimates used in the preparation of TECO Energy’s consolidated financial statements. These estimates and assumptions are based on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and judgments under different assumptions or conditions.

See the Notes to the Consolidated Financial Statements for a description of TECO Energy’s accounting policies and the estimates and assumptions used in the preparation of the Consolidated Financial Statements.

Asset Impairments

TECO Energy and its subsidiaries periodically evaluate whether there has been a permanent impairment of an asset as follows:

•

Long-lived assets, when indicators of impairment exist, in accordance with Financial Accounting Standard No. (FAS) 121, Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of, and beginning in 2002, with FAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets; and

•

Recognized goodwill and other intangible assets with indefinite lives, annually in accordance with FAS 142. (See the Goodwill and Other Intangible Assets section.)

The company believes that the accounting estimate related to asset impairments is a critical estimate for the following reasons: 1) it is highly susceptible to change each reporting period as management is required to make assumptions based on expectations of the results of operations for significant/indefinite future periods and/or the then-current market conditions in such periods; 2) electricity markets continue to experience significant price uncertainty with respect to market fundamentals; 3) the ongoing expectations of management regarding the future use of the asset; and 4) the impact of an impairment on reported assets and earnings would be material. The company’s assumptions relating to future results of operations are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. The assumptions made are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities. (See Notes A, C and S to the Consolidated Financial Statements.)

Long-Lived Assets

TECO Energy adopted FAS 144, with no significant impact on earnings, effective Jan. 1, 2002. During the year ended Dec. 31, 2002, the company evaluated certain merchant generation plants for impairment in accordance with FAS 144. The company concluded that the sum of the undiscounted expected future cash flows (excluding interest charges) from each individual plant exceeded the then-current carrying value of the plant. In accordance with FAS 144, the company did not recognize an impairment charge. If an impairment charge were required to be recognized, the amount of the loss would be determined by calculating the difference of the fair value and the then-current carrying value of the asset.

Goodwill and Other Intangible Assets

Prior to 2002, goodwill was amortized each year. As of Dec. 31, 2001, TECO Energy had $166 million of goodwill, net of accumulated amortization of $10 million. The adoption of FAS 142 on Jan. 1, 2002 resulted in the elimination of approximately $5 million of annual amortization. (See Notes C and S to the Consolidated Financial Statements.)

In accordance with the transition provisions of FAS 142, TECO Energy evaluated all reporting units where goodwill is recorded for impairment. Reporting units are generally determined as one level below the operating segment level; however, reporting units with similar characteristics may be grouped under the accounting standard for the purpose of determining the impairment, if any, of goodwill and other intangible assets. For each reporting unit evaluated, the fair value exceeded the carrying value, including goodwill, as of the valuation date, Jan. 1, 2002. During 2002, in accordance with the ongoing requirements of the standard, the company evaluated all reporting units where goodwill is recorded for impairment. The fair value for the reporting units evaluated was generally determined using discounted cash flow models appropriate for the business model of each significant group of assets within each reporting unit. No impairment loss was recorded during 2002 for goodwill or other intangible assets with indefinite lives.

Asset Retirement Obligations

In July 2001, the FASB issued FAS 143, Accounting for Asset Retirement Obligations, which requires the recognition of a liability at fair value for an asset retirement obligation in the period in which it is incurred. Retirement obligations associated with long-lived assets included within the scope of FAS 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. Retirement obligations are included in the scope of the standard only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.

When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its future value. The corresponding amount capitalized at inception is depreciated over the useful life of the asset. The liability must be revalued each period based on current market prices. FAS 143 is effective for fiscal years beginning after June 15, 2002. The company estimates that the adoption of FAS 143 will result in a non-cash increase to net property, plant and equipment of approximately $8 million, a non-cash increase to asset retirement obligation of approximately $10 million, and, as a cumulative effect of change in accounting principle, a non-cash pretax charge of approximately $2 million.

Asset retirement obligations are comprised of significant estimates which, if different, could materially impact the results of TECO Energy. The company believes these are critical estimates because: 1) the fair value of the costs associated with meeting the obligation are impacted by assumptions on discount rates and estimated profit mark-ups by third-party contractors; 2) probability factors associated with the future sale, abandonment or retirement of an asset must be forecasted and considered in the calculations; 3) the expectations and intent of management regarding the future use of long-lived assets; and 4) the impact of the recognition of an asset impairment obligation could be significant. Upon adoption, effective Jan. 1, 2003, TECO Energy and affiliates are maintaining controls and periodically reviewing all new legal arrangements and contractual commitments to ensure that any new potential asset retirement obligations are reviewed and recognized as appropriate. (See Note A to the Consolidated Financial Statements.)

Unconsolidated Affiliates

TECO Energy has investments in unconsolidated affiliates that are accounted for using the equity method of accounting. See the Other Accounting Standards section for a detailed discussion of the accounting policies for unconsolidated affiliates, the anticipated impact of the adoption of a new accounting policy (FIN 46) for consolidation of certain legal entities, and critical assumptions and judgments which must be made regarding the application of the accounting policies. (See Note A to the Consolidated Financial Statements.)

Employee Postretirement Benefits

TECO Energy has a funded non-contributory defined benefit retirement plan covering substantially all employees. The company’s policy is to fund the plan based on actuarially determined contributions within the guidelines set by the Employee Retirement Income Security Act of 1974, as amended (ERISA), for the minimum annual contribution and the maximum allowable as a tax deduction by the IRS. Plan assets are invested in a mix of equity and fixed income securities. In addition, TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 meeting certain service requirements. In addition, the company has unfunded supplemental executive retirement benefit plans—non-qualified, non-contributory defined benefit retirement plans available to certain senior management.

The determination of the benefit expense is a critical estimate due to the following factors: 1) management must make significant assumptions regarding the discount rate, return on assets, rate of salary increases and health care cost trend rates; 2) costs are based on actual employee demographics, including the turnover rate, retirement rate, mortality rate, employment periods, compensation levels and age, each of which are subject to change in any given period; 3) the plan provisions may be changed by management action in future periods; and 4) the impact of changes in any of these assumptions is likely to result in a material impact on the recorded pension obligation and expense. Management reviews these assumptions periodically to reflect the company’s actual experience.

The discount rate for pension cost purposes is the rate at which the pension obligations could be effectively settled. At Dec. 31, 2002, the discount rate used for actuarial purposes was 6.75%, as determined by reference to Moody’s Aa bond rate as of Sep. 30, 2002. A hypothetical 25 basis point change in the discount rate would impact pension expense by approximately $2 million.

The assumed rate of return on assets is the weighted average of expected long-term asset return assumptions. In selecting an assumed rate of return on plan assets, the company considers past performance and economic forecasts for the types of investments held by the plan. At Dec. 31, 2002, the return on assets used for actuarial purposes was 9%. A hypothetical 25 basis point change in the return on assets would impact pension expense by approximately $1 million.

The assumed health care cost trend rate was 12.5% in 2002 and decreases to 5.0% in 2013 and thereafter. A 100 basis point increase in the trend rate would impact the aggregate service and interest cost by $1.1 million for 2002 and the accumulated postretirement benefit obligation by $9.5 million, and a 100 basis point decrease in the trend rate would impact the aggregate service and interest cost by ($0.5) million for 2002 and the accumulated postretirement benefit obligation by ($5.0) million, as of Sept. 30, 2002. (See Note K to the Consolidated Financial Statements.)

Derivative Instruments and Hedging

From time to time, TECO Energy enters into derivative instruments to reduce the exposure to market risks. The company does not enter into derivatives for speculative purposes. See the Quantitative and Qualitative Disclosures About Market Risk section for a discussion of the accounting policy for derivatives and hedging activities, variables used in estimating the fair value of derivative instruments, assumptions made with respect to forecasted transactions, and a discussion of the strategy and objectives related to the use of energy derivatives to mitigate various exposures to risk and uncertainty. (See Notes A and B to the Consolidated Financial Statements.)

Deferred Income Taxes

TECO Energy uses the liability method in the measurement of deferred income taxes. Under the liability method, the company estimates its current tax exposure and assesses the temporary differences resulting from differing treatment of items, such as depreciation for financial statement and tax purposes. These differences are reported as deferred taxes measured at current rates in the consolidated financial statements. The company assesses the likelihood that deferred tax assets will be recovered from future taxable income and to the extent recovery of some portion or all of the deferred tax asset is not believed to be likely, the company would establish a valuation allowance.

At Dec. 31, 2002, TECO Energy had deferred income tax assets of $340 million attributable primarily to alternative minimum tax credit carryover of Section 29 non-conventional fuels tax credits and property-related items. The carrying value of the company’s deferred income tax assets assumes that the company will be able to realize this asset as an offset to future income taxes payable. The company periodically reviews the deferred income tax assets and, to the extent that recovery would be determined to be unlikely, a valuation reserve would be charged to income. The company believes that the accounting estimate related to deferred income taxes, and any related valuation allowance, is a critical estimate for the following reasons: 1) recoverability of future Section 29 non-conventional fuel tax credits is dependent on the generation of sufficient taxable income to use these credits; and 2) administrative actions of the Internal Revenue Service or the U.S. Treasury or changes in law or regulation could eliminate or reduce the availability of Section 29 tax credits. A change in the recoverability of Section 29 tax credits could have a material impact on reported assets and results of operations. (See Notes A and M to the Consolidated Financial Statements.)

Cost Capitalization

During 2002, TECO Energy devoted resources to the completion and construction of additional generation capacity at Tampa Electric and TPS, extension of the transmission network and enhancement to the system’s reliability at Tampa Electric, expansion of the pipeline distribution infrastructure at PGS, normal river barge replacement at TECO Transport and expansion of production capacity at TECO Coal. The cost of additions, including improvements and replacements of property is charged to plant. TECO Energy capitalizes direct costs and certain indirect costs, including the cost of debt and equity capital as appropriate, associated with its construction and retirement activity as prescribed by generally accepted accounting principles and recognized policies prescribed or permitted by the FPSC and/or the FERC. (See the Regulation section.)

The amount of capitalized overhead construction costs is based upon analysis of company and affiliate construction activity. Costs are capitalized based on the activity level of resources allocated to construction activities. As a result, the company’s net income could be impacted by the manner and timing of the deployment of resources to construction activities. However, total cash flow is not impacted by the allocation of these costs to the various construction or maintenance activities. Due to the magnitude of construction undertakings, fluctuations in net income, as a result of cost capitalization, could be significant. Capitalized costs will be expensed as a component of depreciation when the assets are placed in service. (See Notes A and D to the Consolidated Financial Statements.)

Depreciation Expense

TECO Energy provides for depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage, of depreciable property over its estimated service life. The provision for utility plant in service, expressed as a percentage of the original cost of depreciable property, was 4.2% for 2001 and 2002. The company believes the estimated service life corresponds to the anticipated physical life for most assets. However, the company’s estimation of service life is a critical estimate for the following reasons: 1) forecasting the salvage value for long-lived assets over a long timeframe is subjective; 2) changes may take place that could render a technology obsolete or uneconomical; and 3) a change in the useful life of a long-lived asset could have a material impact on reported results of operations and reported assets. Although it is difficult to predict values far into the future, TECO Energy has a long history of actual costs and values that are considered in reaching a conclusion as to the appropriate useful life of an asset. (See Note A to the Consolidated Financial Statements.)

Regulatory Accounting

Tampa Electric’s and PGS’ retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. (See the Regulation section.) As a result, the regulated utilities qualify for the application of FAS 71, Accounting for the Effects of Certain Types of Regulation. This statement recognizes that the actions of a regulator can provide reasonable assurance of the existence of an asset or liability. Regulatory assets and liabilities arise as a result of a difference between generally accepted accounting principles and the accounting principles imposed by the regulatory authorities. Regulatory assets generally represent incurred costs that have been deferred as they are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers from previous collections for costs that are not likely to be incurred.

TECO Energy periodically assesses whether the regulatory assets are probable of future recovery by considering factors such as regulatory environment changes, recent rate orders to other regulated entities in the same jurisdiction, the current political climate in the state, and the status of any pending or potential deregulation legislation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. A change in these assumptions may result in a material impact on reported assets and the results of operations. (See Notes A and D to the Consolidated Financial Statements.)

Revenue Recognition

TECO Energy and its subsidiaries recognize revenues, except as discussed below, on a gross basis when the risks and rewards of ownership have transferred to the buyer and the products are physically delivered or services provided. Revenues for any financial or hedge transactions that do not result in physical delivery are reported on a net basis.

The determination of the physical delivery of energy sales to individual customers is based on the reading of meters, which occurs on a regular basis. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading may be estimated and the corresponding unbilled revenue is estimated. Unbilled revenue is estimated each month primarily based on historical experience, customer-specific factors, customer rates, and daily generation volumes, as applicable. These revenues are subsequently adjusted to reflect actual results.

Revenues for regulated activities at Tampa Electric and PGS are subject to the actions of regulatory agencies. (See the Regulation section.)

The percentage of completion method is used to recognize revenues for certain transportation services at TECO Transport and for long-term engineering or construction-type contracts at TECO Energy Services (formerly known as TECO BGA and BCH Mechanical). The percentage of completion method requires management to make estimates regarding the distance traveled and/or time elapsed for TECO Transport and total costs and work-in-progress for TECO Energy Services. Revenue is recognized by comparing the estimated current total distance traveled or work completed with the total distance or cost estimate for each project. Each month, revenue recognition and realized profit are adjusted to reflect only the percentage of distance traveled or work completed.

Revenues for energy marketing services at Prior Energy and TECO Gas Services are presented on a net basis in accordance with Emerging Issues Task Force No. (EITF) 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, to reflect the nature of the contractual relationships with customers and suppliers. Revenues for risk management and merchant power sales at TPS are reported on a gross basis, except for gains or losses related to hedge accounting, which are reported net of the hedged item or transaction.

TECO Energy estimates certain amounts related to revenues on a variety of factors, as described above. Actual results may be different from these estimates. (See Note A to the Consolidated Financial Statements.)

Other Accounting Standards

Business Combinations

In June 2001, the FASB issued FAS 141, Business Combinations. FAS 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method of accounting. TECO Energy has applied the provisions of FAS 141 since June 30, 2001 to all business combinations initiated after that date. (See the Goodwill and Other Intangible Assets section and Note S to the Consolidated Financial Statements.)

Lease Accounting Amendment

In April 2002, the FASB issued FAS 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. In addition to rescinding the aforementioned statements, FAS 145 amends FAS 13, Accounting for Leases, to eliminate an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. This statement also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. The implementation of FAS 145 has not had a significant impact on TECO Energy’s results.

Exit or Disposal Costs

In July 2002, the FASB issued FAS 146, Accounting for Costs Associated with Exit or Disposal Activities, which addresses the accounting for costs under certain circumstances, including costs to terminate a contract that is not a capital lease, costs to consolidate facilities or relocate employees, and termination benefits provided to employees that are involuntarily terminated under the terms of a one-time benefit arrangement that is not an ongoing benefit arrangement or an individual deferred compensation contract. FAS 146 is effective for disposal activities initiated after Dec. 31, 2002 with early adoption allowed. (See Note T to the Consolidated Financial Statements.)

Gains and Losses on Energy Trading Contracts

On Oct. 25, 2002, the Emerging Issues Task Force issued EITF 02-3, Recognition and Reporting of Gains and Losses on Energy Trading Contracts Under Issues No. 98-10 and 00-17, which eliminates mark-to-market accounting for certain energy trading contracts and changes the presentation of gains and losses for certain derivative contracts. The measurement provisions of the issue are effective for all fiscal periods beginning after Dec. 15, 2002. The net presentation provisions are effective for all financial statements issued after Dec. 15, 2002. In accordance with the recommended transition provisions, TECO Energy reclassified certain amounts in prior periods to present gains and losses on a net basis. (See Note A to the Consolidated Financial Statements.) The adoption of the measurement provisions is not expected to have a material impact.

Guarantor’s Accounting and Disclosure Requirements for Guarantees

In November 2002, the FASB issued FIN 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Guarantees of Indebtedness of Others (an interpretation of FAS No. 5, 57 and 107 and rescission of FAS Interpretation No. 34), which modifies the accounting and enhances the disclosure of certain types of guarantees. FIN 45 requires that upon issuance of certain guarantees, the guarantor must recognize a liability for the fair value of the obligation it assumes under the guarantee. FIN 45’s provisions for the initial recognition and measurement are to be applied to guarantees issued or modified after Dec. 31, 2002. The disclosure requirements are effective for financial statements of annual periods that end after Dec. 15, 2002. (See Note R to the Consolidated Financial Statements.)

Stock-Based Compensation

In December 2002, the FASB issued FAS 148, Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment of FASB Statement No. 123. This standard amends FAS 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for companies that voluntarily change to the fair value based method of accounting for stock-based employee compensation. It also requires prominent disclosure about the effects on reported net income of the company’s accounting policy decisions with respect to stock-based employee compensation in both annual and interim financial statements. The transition provisions and annual disclosure requirements are effective for all fiscal years ending after Dec. 15, 2002, while the interim period disclosure requirements are effective for all interim periods beginning after Dec. 15, 2002. TECO Energy does not anticipate the adoption of the disclosure provisions of this standard to have a material impact. (See Note I to the Consolidated Financial Statements.)

Variable Interest Entities

The equity method of accounting is used to account for investments in partnership and corporate entities in which TECO Energy or its subsidiary companies do not have either a majority ownership or exercise control. On Jan. 17, 2003, the FASB issued FIN 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51, which requires a new approach in determining if a reporting entity should consolidate certain legal entities, including partnerships, limited liability companies, or trusts, among others, collectively defined as variable interest entities or VIEs. A legal entity is considered a VIE if it does not have sufficient equity at risk to finance its own activities without relying on financial support from other parties. If the legal entity is a VIE, then the reporting entity that is the primary beneficiary must consolidate it. Even if a reporting entity is not obligated to consolidate a VIE, then certain disclosures must be made about the VIE if the reporting entity has a significant variable interest. Certain transition disclosures are required for all financial statements issued after Jan. 31, 2003. The on-going disclosure and consolidation requirements are effective for all interim financial periods beginning after Jun. 15, 2003.

The determination of the applicability of FIN 46 is complex and requires management to make significant assumptions related to: 1) the reasonable possibility that an entity may be a VIE in which the company has a significant variable interest at Dec. 31, 2002; 2) the rights, obligations, and activities of all other equity investors in the potential VIE; 3) the anticipated variability in the potential VIE’s net income or loss, the fair value of its assets not already included in net income or loss, and certain fees paid to related and unrelated third parties; and 4) the magnitude of the company’s variable interest as compared to the variable interests of all other variable interest holders. Each of these assumptions could significantly impact the conclusion of the company to consolidate the legal entity.

Based on a preliminary review, TECO Energy believes it is reasonably possible that FIN 46 may impact the accounting for certain unconsolidated affiliates. Management is continuing to assess the extent of the relationships and obtain adequate information upon which to base appropriate conclusions. Below is a discussion of the legal entities existing as of Dec. 31, 2002 that TECO Energy considers to be possibly subject to either: 1) additional disclosure requirements; or 2) consolidation by the company, in accordance with FIN 46.

TPS entered into a joint venture, TPGC, to build, own and operate the Union and Gila River power stations. As of Dec. 31, 2002, TPGC is a development stage partnership that may meet the definition of a VIE. The third-party debt financing at TPGC is non-recourse and does not create an estimated loss exposure to TECO Energy. The estimated maximum theoretical loss exposure is approximately the current and guaranteed equity investment in the partnership. (See the TECO Power Services – Construction Activities section, the Capital Investments section, Project Financing of Unconsolidated Affiliates section and Notes A, N and R to the Consolidated Financial Statements.)

TPS completed a transaction whereby certain equipment at the Hardee Power Station was sold to a third party (the Lessor) and leased back under an operating lease agreement with an initial term of 12 years. The original cost of the equipment was $46.6 million. The sole purpose of the Lessor is to own and lease back the equipment to Hardee Power. The lease financing arrangement includes $41.6 million of subordinated debt and $1.4 million of equity contributed by an unrelated third party. If the Lessor were to be consolidated, TPS estimates that it would incur after-tax incremental expenses of approximately $9.5 million over the 12-year term of the lease. (See Note R to the Consolidated Financial Statements.)

TECO Properties formed two limited liability companies with project developers which may meet the definition of a VIE. Hernando Oaks, LLC was formed by TECO Properties with the Pensacola Group to buy and develop a residential community in Hernando County, Florida. Hernando Oaks, LLC had total assets at Dec. 31, 2002 of $18.9 million. TECO Properties’ estimated maximum theoretical loss exposure is its equity investment in this project of approximately $9.7 million.

B-T One, LLC is a limited liability company formed by TECO Properties with Boyd Development Co., the project developer, to develop a residential community. B-T One, LLC had total assets at Dec. 31, 2002 of $13.1 million. TECO Properties’ estimated maximum theoretical loss exposure is its equity investment in this project of approximately $7.5 million.

TECO Propane Ventures (TPV) has an investment in a partnership formed to combine propane operations with the propane operations of three third-party entities. At Dec. 31, 2002, the estimated maximum theoretical loss exposure faced by TPV is its equity investment of approximately $35.1 million and $9.5 million of other potential liabilities. (See the Other Unregulated Companies section and Note S to the Consolidated Financial Statements.)

TECO Transport entered into two separate sale-leaseback transactions for certain vessels which were recognized as sales at the time of each transaction, and are currently recognized as operating leases for the assets. The sale-leaseback transactions were entered into with a third party that may meet the definition of a VIE. TECO Transport currently leases two ocean-going tugboats, four ocean-going barges, five river towboats and 49 river barges. The estimated maximum loss exposure faced by TECO Transport is the incremental cost of obtaining suitable equipment to meet contractual obligations. (See Note R to the Consolidated Financial Statements.)

TECO Energy Services formed a partnership to construct, own and operate a water cooling plant to produce and distribute chilled water to customers via a local distribution loop for use, primarily, in air conditioning systems. The partnership may meet the definition of a VIE in accordance with FIN 46. The estimated maximum theoretical loss exposure associated with this partnership is its equity investment of approximately $3.6 million.

In November 2000, TECO Energy established TECO Capital Trust I (Trust I) for the sole purpose of issuing Trust Preferred Securities (TRuPS) and using the proceeds to purchase company preferred securities from TECO Funding Company I, LLC (TECO Funding). Trust I may be a VIE in accordance with FIN 46. TECO Energy has guaranteed the payments to the holders of the company preferred securities and indirectly, the payments to the holders of the TRuPS, as a result of their beneficial interest in the company preferred securities. In January 2002, TECO Energy sold 17.965 million units of mandatorily convertible equity units in the form of 9.5% equity units at $25 per unit. Each equity unit consisted of $25 in principal amount of a trust preferred security of TECO Capital Trust II (Trust II), a Delaware business trust formed for the purpose of issuing these securities and using the proceeds to purchase company preferred securities from TECO Funding Company II, LLC. Trust II may meet the definition of a VIE in accordance with FIN 46. The estimated maximum loss exposure is not expected to be incrementally significant to obligations currently recognized by TECO Energy for activities associated with Trust I or Trust II. (See Note G to the Consolidated Financial Statements.)

As a result of the conversion of a loan to a Panda subsidiary on Jan. 3, 2003, TPS has an equity interest in the TIE projects. (See the TECO Power Services — Construction Activities section.) The estimated maximum theoretical loss exposure is TPS’ equity investment of $137 million. (See Note N to the Consolidated Financial Statements.)

Non-Operating Items Impacting Net Income From Continuing Operations

2002 Items

In 2002, TECO Energy’s results included a $3.0-million after-tax charge at TECO Investments related to an aircraft leased to US Airways, which has filed for bankruptcy. Results at TPS include a $5.8-million after-tax asset valuation charge for the proposed sale of its interests in generating facilities in the Czech Republic. Results at TECO Energy include a $34.1-million pretax ($20.9-million after-tax) charge related to a debt refinancing.

2001 Items

In 2001, TECO Energy’s results included charges to adjust asset valuations totaling $7.2 million after-tax. The adjustments included a $6.1-million after-tax charge related to the sale of TPS’ minority interests in EGI, which owns smaller power generation projects in Central America, and a $1.1-million after-tax charge related to the sale of leveraged leases at TECO Investments.

2000 Items

In 2000, TECO Energy’s results included an $8.3-million after-tax gain from the US Propane and Heritage Propane transactions offset by after-tax charges of $5.2 million to adjust the value of leveraged leases and $3.8 million to adjust property values at TECO Properties.

Discontinued Operations

In September 2002, as a component of its cash raising plans, 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 from 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.

TECO Coalbed Methane’s 2002 net income was $31.4 million including a $7.7-million after-tax net gain on the $42 million portion of the sale proceeds. These results reflect production of 14.2 billion cubic feet (Bcf), compared to 15 Bcf in 2001 at an effective gas price, including the effects of hedging, of about $2.80 per thousand cubic feet (Mcf), an almost 20 percent lower realized price than in 2001.

2001 net income increased as a result of higher gas prices which more than offset naturally declining production. Effective gas prices, including the effects of hedging, increased 33 percent to $3.66 per Mcf and production was 15 Bcf. Effective Jan. 1, 2001, TECO Energy had derivatives in place at TECO Coalbed Methane that qualified for cash flow hedge accounting treatment under FAS 133. As a result of the adoption of FAS 133, TECO Energy recorded an initial derivative liability of $19.0 million and an after-tax reduction to OCI of $12.6 million.

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, $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.

Other Income (Expense)

In 2002, Other Income (Expense) of $47.2 million included $60.7 million from construction-related and loan agreements with Panda Energy and earnings on the equity investment in EEGSA at TPS, and income from the investment in TPV, partially offset by the $9.4 million pretax ($5.8 million after-tax) asset valuation charge for TPS’ proposed sale of its minority interest in generating facilities in the Czech Republic and a $34.1 million ($20.9 million after-tax) pretax charge related to a TECO Energy debt refinancing completed in 2002.

In 2001, Other Income (Expense) of $51.9 million included $27.1 million from construction-related and loan agreements with Panda Energy and earnings on the equity investment in EEGSA at TPS, and income from the investment in TPV, partially offset by a $9.9 million pretax ($6.1 million after-tax) charge for TPS’ sale of its minority interest in EGI.

Equity AFUDC at Tampa Electric, which is included in Other Income, was $24.9 million in 2002, $6.6 million in 2001 and $1.6 million in 2000. AFUDC is expected to be about $20 million in 2003 before declining in 2004, primarily reflecting Tampa Electric’s growing investment in the Gannon to Bayside repowering. With the conversion of the loan to Panda Energy related to the TIE projects to an ownership interest, (see the TECO Power Services – Construction Activities section) the interest income related to these loans will be eliminated in 2003.

Interest Charges

Interest expense was $147.1 million in 2002 compared with $164.0 million in 2001 and $167.6 million in 2000. The decline in 2002 was primarily because of lower short-term debt rates and balances and a favorable settlement with the Internal Revenue Service regarding disputed income tax amounts for which interest had been previously paid, partially offset by higher distributions on preferred securities due to the issuance of mandatorily convertible equity units in January 2002. The slight decrease in 2001 was primarily because of lower short-term debt rates.

Income Taxes

Income taxes decreased in 2002, reflecting greater non-taxable AFUDC equity and a substantial increase in tax credits associated with the production of non-conventional fuels. In 2001 income tax expense decreased, reflecting higher taxable income offset by an increase in tax credits associated with the production of non-conventional fuels. Income tax expense as a percentage of income from continuing operations before taxes was –14.8 percent in 2002, –0.8 percent in 2001 and 11.4 percent in 2000.

The cash payment for federal income taxes, as required by the alternative minimum tax rules, was $71.9 million, $52.4 million and $83.9 million in 2002, 2001 and 2000, respectively.

Total income tax expense was reduced by the Federal tax credit related to the production of non-conventional fuels, under Section 29 of the Internal Revenue Code. This tax credit totaled $107.3 million in 2002, $86.2 million in 2001 and $52.1 million in 2000. These tax credits are generated annually on qualified production at TECO Coal through Dec. 31, 2007, subject to changes in law, regulation or administration that could impact the qualification of Section 29 tax credits.

The tax credit is determined annually and is estimated to be $1.08 per million Btu for 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 this limitation to have been effective.

In 2002, 2001 and 2000, the decreased income tax expense also reflected the impact of increased overseas operations with deferred U.S. tax structures. The decrease related to these deferrals was $8.1 million, $7.2 million and $9.3 million for 2002, 2001 and 2000, respectively.

The income tax effect of gains and losses from the discontinued operations of TECO Coalbed Methane is shown as a component of results from discontinued operations.

Enron Related Matters

TPS has filed a claim in the Enron bankruptcy proceeding associated with the NEPCO “swept cash” (see the TECO Power Services – Construction Activities section) for the four projects in the amount of $214 million. This is a gross amount and does not take into account efficiencies in the projects and other similar credits. The bankruptcy judge appointed an examiner in October 2002 to evaluate whether the “swept cash” lost by all NEPCO customers at the time of the bankruptcy can be traced from NEPCO to Enron and then to Enron’s use of the funds. That report is expected by the end of the first quarter of 2003, and if it is favorable, the judge should require that the amount of the traceable funds be returned to the bankrupt estate of NEPCO. This result would improve significantly TPS’ likelihood of recovering most of the cash. Since the appointment of the examiner, TPS and others have filed adversary proceedings in the bankruptcy.

TECO Energy has negotiated an agreement with Enron, pending approval of the Creditors Committee, to settle the previously reported $3.5 million of potential trade payables exposure as a result of the Enron bankruptcy. Action by the Creditors Committee is expected by the end of March 2003. The net financial impact of the agreement is reflected in consolidated net income and no future financial impact is expected.

Environmental Compliance

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 Oct. 5, 2000, and a Consent Final Judgment with the Florida Department of Environmental Protection (FDEP), effective Dec. 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 its power plants.

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 oxides (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.

Particulate matter 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.

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 Dec. 31, 2002, Tampa Electric Company has estimated its ultimate financial liability to be approximately $20 million, and this amount has been reflected in the company’s financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, 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.

Regulation

Tampa Electric Rate Stabilization Strategy

Tampa Electric’s objectives of stabilizing prices from 1996 through 1999 and securing fair earnings opportunities during this period were accomplished through a series of agreements entered into in 1996 with Florida’s Office of Public Counsel (OPC) and the Florida Industrial Power Users Group (FIPUG), which were approved by the FPSC. Prior to these agreements, the FPSC approved a plan submitted by Tampa Electric to defer certain 1995 revenues.

In general, under these agreements Tampa Electric was allowed to defer revenues in 1995 and 1996 during the construction of Polk Unit 1 and recognize these revenues in 1997 and 1998 after commercial operation of the unit. Other components of the agreements were a base rate freeze through 1999 and refunds to customers totaling $50 million during the period from October 1996 through December 1998, while Tampa Electric was allowed recovery of the capital costs incurred for the Polk Unit 1 project.

In October 2000, the FPSC staff recommended a refund of $6.1 million for the final year of the agreements. OPC objected to certain interest expenses recognized in 1999 that were associated with prior years’ tax positions and used to calculate the amount to be refunded. Following a review by the FPSC staff, the FPSC agreed in December 2000 that the original $6.1 million was to be refunded to customers. In February 2001, OPC protested the FPSC’s decision. The FPSC held hearings on the issue in August 2001 and upheld its original decision. In January 2002, the OPC filed a motion with the FPSC asking for reconsideration of its decision, alleging the FPSC relied on erroneous information. This was not granted, and Tampa Electric made refunds of about $6.4 million associated with 1999 in 2002.

Since the expiration of the agreements, 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. Tampa Electric expects to continue earning within its allowed ROE range.

Peoples Gas Rate Proceeding

On Jun. 27, 2002, PGS filed a petition with the FPSC to increase its service rates. The requested rates would have resulted in a $22.6 million annual base revenue increase, reflecting a ROE midpoint of 11.75 percent.

On the date of the FPSC hearing, PGS agreed to a settlement with all parties involved, and a final Commission order was granted on Dec. 17, 2002. The company received authorization to increase annual base revenues by $12.05 million. The new rates allow for an 11.25 percent midpoint ROE and a capital structure with 57.43 percent equity and were effective after Jan. 16, 2003.

Cost Recovery Clauses

In September 2002, Tampa Electric filed with the FPSC for approval of fuel and purchased power, capacity, environmental and conservation cost recovery clause rates for the period January 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. Accordingly, Tampa Electric’s residential customer rate per 1,000-kilowatt hours increased to $94.14. The rates include projected costs associated with environmental projects required under the EPA Consent Decree and the FDEP Consent Final Judgment. They also reflect natural gas purchases for the company’s repowered Bayside Unit 1.

During 2002, PGS’ purchased gas adjustment remained stable, as no significant natural gas spikes occurred. The actual purchased gas adjustment rate paid by consumers was significantly lower than the FPSC approved cap. In December 2002, PGS’ purchased gas adjustment cap for 2003 was approved as filed.

Utility Competition: Electric

Tampa Electric’s retail electric business is substantially free from direct competition with other electric utilities, municipalities and public agencies. At the present time, the principal form of competition at the retail level consists of self-generation available to larger users of electric energy. Such users may seek to expand their alternatives through various initiatives, including legislative and/or regulatory changes that would permit competition at the retail level. Tampa Electric intends to retain and expand its retail business by managing costs and providing high-quality service to retail customers.

There is presently active competition in Florida’s wholesale power markets, increasing largely as a result of the Energy Policy Act of 1992 and related federal initiatives. However, the state’s Power Plant Siting Act, which sets the state’s electric energy and environmental policy and governs the building of new generation involving steam capacity of 75 megawatts or more, requires that applicants demonstrate that a plant is needed prior to receiving construction and operating permits.

In February 2002, the FPSC began holding workshops to discuss suggested changes to an associated rule originally adopted by the FPSC in 1994, requiring investor-owned electric utilities (IOUs) to issue Requests for Proposals (RFP) prior to filing a petition for Determination of Need. The RFP process has been used as a tool to measure the cost-effectiveness of new generation. After a series of workshops, a rule hearing was held in December 2002 and, as a result, the FPSC made modifications to the rule that provide a mechanism for expedited dispute resolution; allow bidders to submit new bids whenever the IOU revises its costs estimates for its self-build option; require IOUs to disclose the methodology and criteria to be used to evaluate the bids; and provide more stringent standards for the IOUs to recover costs overruns in the event the self-build option is deemed the most cost-effective. The new rule will become effective for requests for proposal for applicable capacity additions, prospectively.

Regional Transmission Organization (RTO)

In December 1999, the Federal Energy Regulatory Commission (FERC) issued Order No. 2000, encouraging the development of RTOs. This rule was driven by the FERC’s continuing effort to increase open access to transmission facilities in large, regional markets.

The peninsular Florida IOUs made joint RTO filings to the FERC in October and December 2000. In the filing, Tampa Electric agreed with the other Florida IOUs to form an RTO to be known as GridFlorida LLC. GridFlorida would independently control the transmission assets of the filing utilities, as well as other utilities in the region that choose to join. The RTO would be an independent, investor-owned organization that would have control of the planning and operations of the bulk power transmission systems of the utilities within peninsular Florida. In addition, GridFlorida was proposed to be a transmission company that would own transmission assets. Tampa Electric planned to contribute its transmission assets to GridFlorida in exchange for a passive interest.

In March 2001, the FERC conditionally approved GridFlorida. In May 2001, the FPSC decided to investigate whether the peninsular Florida IOUs were prudent in complying with FERC’s Order No. 2000. In October 2001, the FPSC ruled that, while the companies were prudent in forming GridFlorida, the FPSC was not satisfied with the transmission-owning features of the GridFlorida filing nor with the proposal that any of the filing utilities transfer ownership of their assets to GridFlorida. Accordingly, the FPSC ordered the companies to develop a new RTO model.

In September 2002, the FPSC issued an order which gave final approval to some aspects of the latest GridFlorida proposal; set some items for further discussion by parties and the FPSC; and set a hearing to address market design. The applicants filed joint testimony that addressed the principles for developing a Florida-specific market design that is consistent with the principles identified in the FERC’s proposed order on standard market design.

In October 2002, the process was held in abeyance after the OPC filed an appeal with the Florida Supreme Court asserting that the FPSC could not relinquish its jurisdictional responsibility to regulate the IOUs and by approving GridFlorida, they were doing just that. Tampa Electric and the other peninsular IOUs will take varying roles to support the FPSC and their prudence determinations. Oral arguments are expected during the first half of 2003, and a decision by the Florida Supreme Court is not expected until late 2003. All activity in development of GridFlorida has ceased pending the outcome of the case and the resolution of certain issues by the FPSC subsequent to that outcome.

Federal Energy Regulatory Commission (FERC) Restructuring Initiatives

The FERC has increased its focus on creating a more efficient electric industry, and it has begun several key initiatives since its RTO order in late 1999 (see the Regional Transmission Organization section). These include the development of a Standard Market Design (SMD) for electric wholesale markets; standard generator interconnection terms, conditions and pricing; enhanced affiliate standards of conduct; and more comprehensive public information initiatives. The most significant of these initiatives relates to development of a SMD through rulemaking that will provide certain structural changes to how transmission service is provided, accessed and priced. A final rule in this matter is expected sometime in 2003. TECO Energy, through its appropriate operating companies, is active in providing comments on all initiatives and plans to remain active in ensuring its positions are fairly represented. Many of the initiatives being proposed by the FERC would be beneficial both to Tampa Electric and TPS.

TPS Federal and State Regulatory and Legislative Involvement

Along with TECO Energy’s active involvement in restructuring initiatives, TPS has been proactively involved in regulatory and legislative forums in the markets in which it competes including Arizona, Texas, Arkansas, Mississippi, and Louisiana. This has included repeal in part and sometimes in total of wholesale and retail deregulation rules and laws in Arizona and Arkansas.

Arizona Public Service (APS), the largest investor-owned electric utility in the state, filed with the Arizona Corporation Commission (ACC) a request for a partial variance from the state’s competition rules established in 1999. APS requested that it be exempt from its obligation, beginning on Jan. 1, 2003, to purchase at least 50 percent (about 3,000 MW) of its load requirements through a formal, arms-length, competitive procurement process and sought instead to purchase almost all of its load requirements from its unregulated affiliate, Pinnacle West Energy Corporation (PWEC). APS asserted that, due to the California crisis and the Enron collapse, the competitive wholesale market was not mature or reliable enough to meet its needs, so it should be permitted to execute a 28-year power purchase agreement between itself and PWEC. Tucson Electric Power Company (TEP) filed a similar variance request with the ACC, although it only sought a postponement of the implementation date, not a long-term power purchase agreement with an affiliated entity. The two requests were stayed by the ACC in late April 2002, and a docket was opened to review the future of competition in Arizona. In August 2002, the Commission ordered APS not to divest its current rate-based generating facilities to its affiliate, and to continue to participate in a parallel proceeding to determine what portion of its needs will be competitively bid for delivery beginning in the summer of 2003.

Regarding the competitive procurement process, the ACC Staff held numerous workshops, followed by a hearing in November 2002 to determine the amount and procedures for APS’ and TEP’s acquisition of their power requirements. TPS has been active in all aspects of the state’s proceedings. A final determination is expected during the first quarter of 2003 with the competitive procurement process slated to begin by spring.

During this year’s legislative session, the Arkansas Legislature will consider repealing its earlier legislation, which was to initiate retail electric deregulation in Arkansas sometime between October 2003 and October 2005. The incumbent IOUs are advocating a complete repeal of retail deregulation and/or a ten-year postponement of its implementation date. The large consumers and the independent power producers are lobbying for a recommitment to wholesale deregulation in Arkansas, access to the state’s transmission grid, and a “pilot” project for large customers to be able to shop for power in the interim. TPS is supporting this approach while also aligning with other independent power producers to analyze the beneficial impacts to ratepayers from implementing a region-wide, security-constrained, economic dispatch, with consideration given for units’ efficiency and environmental characteristics, including emissions. This is a strategy for displacing the region’s older, less efficient, more polluting generating units so that state-of-the-art, gas-fired, combined-cycle units, such as Union Power Partners, can serve the growing needs of the area. This is a strategy that TPS has advanced at the federal level and other markets it serves.

In Texas, TPS has taken an active role on ERCOT committees, in proceedings at the Public Utility Commission of Texas (PUCT) and in the Legislature, whose session begins in mid-January. Transmission congestion is a major concern in the ERCOT market, and has negatively affected Frontera’s ability to economically operate. Several initiatives within the ERCOT committees and at the PUCT are underway to address these ongoing congestion problems.

Frontera appealed specific ERCOT protocols with the PUCT, because of inadequate compensation for ERCOT’s high usage levels of Frontera’s units during times of regional congestion. Originally, the intent of the protocols was to allow ERCOT to acquire energy and capacity, when only critically necessary and on an infrequent basis from the region’s existing generating units. Due to local transmission congestion in the Rio Grande Valley, Frontera was frequently requested by ERCOT to start-up and relieve the region’s congestion. Frontera, however was not compensated sufficiently for providing this ancillary service in 2002. The appeal process is underway and is expected to be concluded by the end of the first quarter of 2003.

Transmission Rates

In October 2002, Tampa Electric submitted a FERC filing to change its transmission and ancillary services rates under the company’s open access transmission tariff. These rates apply to wholesale transmission users of Tampa Electric’s transmission system and do not affect retail service rates. In December, the FERC accepted the filing and set the matter for settlement negotiations and a potential hearing should the settlement process fail. Settlement discussions began in January 2003.

Utility Competition: Gas

Although PGS is not in direct competition with any other regulated distributors of natural gas for customers within its service areas, there are other forms of competition. At the present time, the principal form of competition for residential and small commercial customers is from companies providing other sources of energy, including electricity.

Competition is most prevalent in the large commercial and industrial markets. In recent years, these classes of customers have been targeted by companies seeking to sell gas directly, by transporting 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.

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.

Corporate Governance

Recently, legislation, rules and proposed rules and guidelines were issued by the United States Congress, the Securities and Exchange Commission (SEC), the New York Stock Exchange (NYSE) and other interested groups designed to ensure corporate accountability, improve corporate governance and restore investor confidence. In 2002, the NYSE issued proposed standards for listed companies; the SEC issued the requirement that the largest public companies certify quarterly financial reports, one of 18 directives issued from December 2001 through December 2002. Also in 2002, the President signed the Sarbanes-Oxley Act which, among other things, requires certification of financial statements with criminal penalties for filing false statements.

These rules and proposals require independence by the Board of Directors, define committees of the Board of Directors with charters and review processes, require an internal audit function, a code of ethics for the chief executive officers, senior financial officers and directors, adequate internal controls to detect fraud, adequate training for members of the Board of Directors, increased oversight of financial disclosure by the Audit Committee of the Board, a shorter time period to report insider selling of company shares and other important items.

For many years, TECO Energy’s Board of Directors has primarily consisted of independent directors, the committee structures recommended in the various proposals were already in place and the company has an effective internal audit function. In addition, the company has had a code of ethics for all officers and employees, and it was expanded to include the Board of Directors in 2002. TECO Energy has always had controls for full and complete financial reporting and disclosure, and in response to the new requirements, they have been formalized and are reviewed for effectiveness quarterly.

TECO Energy’s CEO and CFO certified its first and second quarter Reports on Form 10-Q for 2002, all interim Reports on Form 8-K and its Annual Report on Form 10-K for 2001 as required by the SEC in August 2002. The certifications, which contained no exceptions, attested to the accuracy of the reports and were signed following a review by the Audit Committee of the company’s Board of Directors. In compliance with the Sarbanes-Oxley Act, certifications of the company’s second and third quarter Reports on Form 10-Q have been filed with the SEC.

In addition, the CEO and CFO evaluated the effectiveness of the company’s disclosure controls and procedures in conjunction with the filing of quarterly financial statement certifications, as required under the new legislation, and found that the disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the company required to be included in the company’s reports. Processes are in place to meet these requirements on a quarterly basis.

Transactions with Related and Certain Other Parties

The company and its subsidiaries had certain transactions, in the ordinary course of business, with entities in which directors of the company had interests that are reported in TECO Energy’s annual proxy statement and Tampa Electric’s annual regulatory filings. These transactions, primarily for legal services, were not material for the periods ended Dec. 31, 2002 and 2001. There are no material transactions of this type where the payments are in excess of those that would be paid under an arms-length transaction. TECO Energy has interests in unconsolidated affiliates, which are discussed in the TECO Power Services, Other Unregulated Companies and Off-Balance Sheet Financing sections.

Tampa Electric and TECO-Panda Generating Company (TPGC) II entered into an assignment and assumption agreement whereby Tampa Electric obtained TPGC II’s rights and interests to four combustion turbines being purchased from General Electric, and assumed the corresponding liabilities and obligations for such equipment. In accordance with the terms of the assignment and assumption agreement, Tampa Electric paid $62.5 million to TPGC II as reimbursement for amounts already paid to General Electric by TPGC II for such equipment.

TPS Arkansas Operations Company and TPS Arizona Operations Company, both wholly-owned subsidiaries of TPS, had a combined receivable from Union and Gila River of $0.8 million as of Dec. 31, 2002.

In addition, TPS recognized income on the non-TPS portion of notes receivable from unconsolidated affiliates in which TPS holds joint venture interests and from credit support for the TPGC joint venture (see Notes A and N to the Consolidated Financial Statements). The notes receivable from unconsolidated affiliates include:

($ millions)	Rate		Dec. 31, 2002		Dec. 31, 2001
Notes receivable from:
Panda Energy	14	%	$	137.0	$	92.7
Energeticke Centrum Kladno	6	%		1.4		—
Mosbacher Power Partners L.P.	12	%		—		13.1
Mosbacher Power Partners L.P.	9	%		13.7		21.1
Mosbacher Power Partners L.P.	12	%		—		6.2
EEGSA	6.81	%(1)		11.1		10.9
TPGC—Gila River	7.79	%(1)		369.5		37.5
TPGC—Union Power	6.58	%(1)		426.3		86.7

(1)

Current rate at Dec. 31, 2002.

TPS’ position in the Odessa and Guadalupe power stations in Texas was in the form of a $137 million loan to a Panda Energy International subsidiary, which is a partner in TIE at Dec. 31, 2002. This loan converted into an ownership interest on Jan. 3, 2003. The conversion gives TPS an opportunity to have an effective economic interest estimated at 75 percent of Panda’s 50-percent interest in these projects (approximately 1,000 MW) over the life of the projects. TPS is evaluating its options relative to its ownership position in these projects and is targeting to structure its interest in such a manner that it will cover its cash costs in 2003 and mitigate any impact on earnings at TPS in 2003. (See Strategy and Outlook section.)

In February 2002, the TPS and Panda affiliates that comprise the joint venture that owns the Union and Gila River projects entered into an arrangement obligating TPS to purchase and Panda to sell Panda’s interest in the joint venture in 2007 for $60 million. Panda has the right to cancel the purchase arrangement by paying TPS $20 million or a lesser amount under certain circumstances. The purchase arrangement can result in TPS’ purchase of the interest prior to 2007 if Panda defaults on a bank loan made to Panda using the purchase arrangement as collateral or if TECO Energy permits its debt-to-capital ratio to exceed 65.0 percent, permits its EBITDA/interest ratio to fall below 1.5 times or it defaults on the payment of indebtedness in excess of $50 million. TECO Energy’s debt-to-capital ratio at Dec. 31, 2002 was 55.9 percent and its EBITDA/interest ratio was 3.6 times.

Investment Considerations

The following are certain factors that could affect TECO Energy’s future results. They should be considered in connection with evaluating forward-looking statements contained in this report and otherwise made by or on behalf of TECO Energy because these factors could cause actual results and conditions to differ materially from those projected in those forward-looking statements.

Financing Risks

TECO Energy has substantial indebtedness, which could adversely affect its financial condition and financial flexibility.

In recent years, TECO Energy has significantly expanded its indebtedness. This increase in debt levels has increased the amount of fixed charges TECO Energy is obligated to pay. The level of indebtedness and restrictive covenants contained in its debt obligations could limit its ability to obtain additional financing or refinance existing debt.

Some of TECO Energy’s debt obligations contain financial covenants related to debt-to-capital ratios and interest coverage that could prevent the repayment of subordinated debt and the payment of dividends if those payments would cause a violation of the covenants. (See Covenants in Financing Agreements section.) TECO Energy’s failure to comply with any of these covenants, as well as its ratings maintenance covenants discussed below, or to meet its payment obligations, could result in an event of default which, if not cured or waived, could result in the acceleration of other outstanding debt obligations. TECO Energy may not have sufficient working capital or liquidity to satisfy its debt obligations in the event of an acceleration of all or a significant portion of its outstanding obligations. Additionally, such an acceleration would also affect the company’s ability to pay dividends. Furthermore, if TECO Energy had to defer interest payments on its subordinated notes that support the distributions on its outstanding trust preferred securities, TECO Energy would be prohibited from paying cash dividends on its common stock until all unpaid distributions on the subordinated notes were made.

TECO Energy also incurs obligations in connection with the operations of its subsidiaries and affiliates, which do not appear on the balance sheet, including in connection with the development of power projects by unconsolidated affiliates. These obligations take the form of guarantees, letters of credit and contractual commitments, as are described in the sections titled Off-Balance Sheet Financing and Liquidity, Capital Resources. In addition, TECO Energy’s unconsolidated affiliates from time to time incur non-recourse debt to finance their power projects. Although TECO Energy is not obligated on that debt, its investments in those unconsolidated affiliates and its commitments with respect to those power projects are at risk if the projects are not successfully developed.

TECO Energy’s financial condition and ability to access capital and pay dividends may be materially adversely affected by further ratings downgrades.

In September 2002, Moody’s, S&P, Inc. and Fitch, lowered their ratings on the senior unsecured debt securities of TECO Energy.

Those downgrades and any future downgrades may affect TECO Energy’s ability to borrow and may increase its financing costs, which may decrease earnings. TECO Energy is also likely to experience greater interest expense than it may have otherwise if, in future periods, it replaces maturing debt with new debt bearing higher interest rate spreads due to its lower credit ratings. In addition, such downgrades could adversely affect TECO Energy’s relationships with customers and counterparties.

In addition to affecting the cost of borrowing, lower credit ratings may affect the amount of indebtedness, types of financing structures and debt markets that are available. Finally, TECO Energy’s failure to comply with its ratings maintenance covenants could result in an event of default under certain of its debt obligations, which if not cured or waived, could result in the acceleration of other outstanding debt obligations and would affect its ability to pay dividends. (See Bank Credit Facilities and Covenants in Financing Agreements sections.)

If TECO Energy is unable to reduce capital expenditures or successfully complete planned asset sales and other transactions to the extent anticipated, its financial condition and results could be adversely affected.

Part of TECO Energy’s business plan for 2003 includes reducing previously anticipated capital expenditures by approximately $250 million in order to maximize cash flows and reduce the need for external financings. TECO Energy cannot be sure that it will be successful in achieving reductions in that amount. The business plan also includes the sale of the majority of its interest in facilities that produce synthetic fuel which qualifies for Section 29 tax credits at TECO Coal and Tampa Electric’s Polk Power Station’s coal gasification unit. TECO Energy cannot be certain, however, that it will find purchasers or realize the expected value of these transactions with the anticipated impact on its cash flow position. Depending on the success of these planned expenditure reductions and asset sales transactions, TECO Energy may need to seek external financings, which, in the case of debt financings, could adversely affect its balance sheet strength and apply downward pressure on the credit ratings, and, in the case of equity financings, could have a dilutive effect to equity holders and earnings-per-share results.

Because TECO Energy is a holding company, it is dependent on cash flow from its subsidiaries, which may not be available in the amounts and at the times it is needed.

TECO Energy is a holding company and dependent on cash flow from its subsidiaries to meet its cash requirements that are not satisfied from external funding sources. Some subsidiaries have indebtedness containing restrictive covenants which, if violated, would prevent them from making cash distributions to TECO Energy. In particular, Tampa Electric’s first mortgage bonds indenture contain restrictions on distributions on its common stock, and certain long-term debt at Tampa

Electric’s PGS division prohibits payment of dividends to TECO Energy if Tampa Electric Company’s consolidated shareholders’ equity is not at least $500 million. At Dec. 31, 2002, Tampa Electric’s unrestricted retained earnings available for dividends on its common stock were approximately $189 million and its consolidated shareholders’ equity was approximately $1.8 billion. Also, TECO Energy’s wholly-owned subsidiary, TECO Diversified, the holding company for TECO Transport, TECO Coal and TECO Solutions, has a guarantee related to a coal supply agreement that could limit the payment of dividends to TECO Energy.

TECO Energy is vulnerable to interest rate changes and may not have access to capital at favorable rates, if at all.

Changes in interest rates and capital markets generally affect TECO Energy’s cost of borrowing and access to these markets. TECO Energy cannot be sure that it will be able to accurately predict the effect those changes will have on the cost of borrowing or access to capital markets.

Independent Power Project Risks

TPS’ existing and planned power plants are affected by market conditions, and it may not be able to sell power at prices that enable it to recover its investments in the plants.

TPS is currently operating, constructing and investing in power plants that do not currently have long-term contracts for the sale of power. These power plants may sell at least a portion of their power based on market conditions at the time of sale, so TPS cannot predict with certainty:

•

the amount or timing of revenue it may receive from power sales from operating plants;

•

the differential between the cost of operations (in particular, natural gas prices) and power sales revenue;

•

the effect of competition from other suppliers of power;

•

regulatory actions that may affect market behavior, such as price limitations or bidding rules imposed by the FERC or reimposition of regulation in power markets;

•

the demand for power in a market served by its plants relative to available supply;

•

the availability of transmission to accommodate the sale of power; or

•

whether TPS will recover its initial investment in these plants.

At present, several of the wholesale markets supplied by so-called “merchant” power plants are experiencing significant pricing declines due to excess supply and weak economies. Consequently, only a portion of the projected output of TPS’ plants has been hedged for 2003 and 2004. TPS’ results could be adversely affected if it is unable to sufficiently sell the output of its plants at a premium to forward curve prices or if TECO Energy needs to write off any capital already invested in projects.

TECO Energy’s forecast assumes that TPS will manage these risks by:

•

optimizing among a mix of forward on-peak energy sales, daily and hourly spot market sales of capacity, energy and ancillary services, and longer-term structured transactions;

•

avoiding short positions; and

•

retaining flexibility to defer, if and where possible and advisable, construction of output capacity in a market that has become oversupplied.

However, TECO Energy cannot be sure how successfully it will be able to implement these risk management measures. For instance, in oversupplied markets, entering into forward contracts could be difficult.

TPS may be unable to successfully complete and finance current and future projects on schedule and within budget.

TPS currently has new power generating facilities under construction. The construction of these facilities, as well as any future construction projects, involves risks of shortages and inconsistent qualities of equipment and material, labor shortages and disputes, engineering problems, work stoppages, unanticipated cost increases, and environmental or geological problems. In addition, the development of independent power plants involves considerable risks, including successful siting, permitting, financing and construction, contracting for necessary services, fuel supplies and power sales and performance by project partners. Any of these events could delay a project’s construction schedule or increase its costs, which may impact TPS’ ability to generate sufficient cash flow and service its related non-recourse project debt.

TPS marketing and risk management policies may not work as planned, and it may suffer economic losses despite such policies.

TPS actively manages the market risk inherent in its energy and fuel positions. Nonetheless, adverse changes in energy and fuel prices may result in losses in earnings or cash flows and adversely affect the balance sheet. TPS marketing and risk management procedures may not always be followed or may not work as planned. As a result, it cannot predict with precision the impact that its marketing, trading and risk management decisions may have on its business, operating results or financial position. In addition, to the extent it does not cover the entire exposure of assets or positions to market price volatility,

or the hedging procedures do not work as planned, fluctuating commodity prices could cause sales and net income to be volatile.

TPS’ marketing and risk management activities also are exposed to the credit risk that counterparties to its transactions will not perform their obligations. Should counterparties to these arrangements fail to perform, TPS may be forced to enter into alternative hedging arrangements, honor underlying commitments at then-current market prices or otherwise satisfy its obligations on unfavorable terms. In that event, its financial results would likely be adversely affected.

General Business and Operational Risks

General economic conditions may adversely affect TECO Energy’s businesses.

TECO Energy’s businesses are affected by general economic conditions. In particular, the projected growth in Tampa Electric’s service area and in Florida is important to the realization of Tampa Electric’s and PGS’ forecasts for annual energy sales growth. An unanticipated downturn in the local area’s or Florida’s economy could adversely affect Tampa Electric’s or PGS’ expected performance.

TECO Energy’s unregulated businesses, particularly TECO Transport, TECO Coal and TPS, are also affected by general economic conditions in the industries and geographic areas they serve, both nationally and internationally. TPS’ investment in Empresa Eléctrica de Guatemala, S.A. depends on growth in the relevant service areas and in annual energy sales.

Potential competitive changes may adversely affect TECO Energy’s gas and electricity businesses.

The U.S. electric power industry has been undergoing restructuring. Competition in wholesale power sales has been introduced on a national level. Some states have mandated or encouraged competition at the retail level and, in some situations, required divestiture of generating assets. While there is active wholesale competition in Florida, the retail electric business has remained substantially free from direct competition. Changes in the competitive environment occasioned by legislation, regulation, market conditions or initiatives of other electric power providers, particularly with respect to retail competition, could adversely affect Tampa Electric’s business and its performance.

The gas distribution industry has been subject to competitive forces for several years. Gas services provided by PGS are now unbundled for all non-residential customers. Because PGS earns margins on distribution of gas, but not on the commodity itself, unbundling has not negatively impacted PGS results. However, future structural changes that cannot be predicted could adversely affect PGS.

TECO Energy’s gas and electricity businesses, both utility and independent, are highly regulated and any changes in regulatory structures could lower revenues or increase costs or competition.

Tampa Electric, TPS and PGS operate in highly regulated industries. Retail operations, including the prices charged, are regulated by the FPSC, and Tampa Electric’s and TPS’ wholesale power sales and transmission services are subject to regulation by the FERC. Changes in regulatory requirements or adverse regulatory actions could have an adverse effect on their performance by, for example, increasing competition or costs, threatening investment recovery or impacting rate structure.

TECO Energy’s businesses are sensitive to variations in weather and have seasonal variations.

Most of TECO Energy’s businesses are affected by variations in general weather conditions and unusually severe weather. Tampa Electric’s, PGS’ and TPS’ energy sales are particularly sensitive to variations in weather conditions. Those companies forecast energy sales on the basis of normal weather, which represents a long-term historical average. Significant variations from normal weather could have a material impact on energy sales. Unusual weather, such as hurricanes, could adversely affect operating costs and sales.

PGS, which has a single winter peak period, is more weather sensitive than Tampa Electric, which has both summer and winter peak periods. Mild winter weather in Florida can be expected to negatively impact results at PGS.

Variations in weather conditions also affect the demand and prices for the commodities sold by TECO Coal, as well as electric power sales from TPS’ merchant power plants. TECO Transport is also impacted by weather because of its effects on the supply of and demand for the products transported. Severe weather conditions could interrupt or slow service and increase operating costs of those businesses.

Electric power marketing may be seasonal. For example, in some parts of the country, demand for, and market prices of, electricity peak during the hot summer months, while in other parts of the country such peaks occur in the cold winter months. As a result, power marketing results may fluctuate on a seasonal basis. The pattern of this fluctuation may change depending on the nature and location of the facilities operated and the terms under which they sell electricity.

Commodity price changes may affect the operating costs and competitive positions of TECO Energy’s businesses.

Most of TECO Energy’s businesses are sensitive to changes in coal, gas, oil and other commodity prices. Any changes could affect the prices these businesses charge, their operating costs and the competitive position of their products and services.

In the case of Tampa Electric, currently fuel costs used for generation are mostly affected by the cost of coal. Future

fuel costs will be impacted by the cost of natural gas as well as coal. Tampa Electric is able to recover the cost of fuel through retail customers’ bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.

Regarding wholesale sales of electricity, the ability to make sales and margins on power sales is currently affected by the cost of coal to Tampa Electric, particularly as it compares to the cost of gas and oil to other power producers.

In the case of TPS, results are impacted by changes in the market price for electricity. The profitability of merchant power plants is heavily dependent on the price for power in the markets they serve. Wholesale power prices are set by the market assuming a cost for the input energy and conversion efficiency, but the fixed costs may not be reflected in the price for spot, or excess power.

In the case of PGS, costs for purchased gas and pipeline capacity are recovered through retail customers’ bills, but increases in gas costs affect total retail prices and therefore, the competitive position of PGS relative to electricity, other forms of energy and other gas suppliers.

TECO Energy relies on some transmission and distribution assets that it does not own or control to deliver wholesale electricity as well as natural gas. If transmission is disrupted, or if capacity is inadequate, its ability to sell and deliver power and natural gas may be hindered.

TECO Energy depends on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity and natural gas it sells to the wholesale market, as well as the natural gas it sells and purchases for use in its electric generation facilities. If transmission is disrupted, or if capacity is inadequate, the ability to sell and deliver products and satisfy contractual and service obligations may be hindered.

The FERC has issued regulations that require wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, there is the potential that fair and equal access to transmission systems will not be available or that sufficient transmission capacity will not be available to transmit electric power as desired. TECO Energy cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets.

In addition, the independent system operators that oversee the transmission systems in certain wholesale power markets have from time to time been authorized to impose price limitations and other mechanisms to address volatility in the power markets. These types of price limitations and other mechanisms may adversely impact the profitability of TECO Energy’s wholesale power marketing business.

The uncertain outcome regarding the creation of regional transmission organizations, or RTOs, may impact operations, cash flows or financial condition.

Tampa Electric is continuing to make progress towards the development of its RTO, which would independently control the transmission assets of participating utilities in peninsular Florida. Given the regulatory uncertainty of the ultimate timing, structure and operations of GridFlorida or an alternate combined transmission structure, TECO Energy cannot predict what effect its creation will have on future consolidated results of operations, cash flow or financial condition.

TECO Energy may be unable to take advantage of its existing tax credits.

TECO Energy derives a portion of its net income from Section 29 tax credits related to the production of non-conventional fuels. Although TECO Energy currently plans to sell a significant portion of the production facilities, until and unless TECO Energy successfully does so, the use of these tax credits is dependent on the generation of sufficient taxable income against which to use the credits. TECO Energy’s forecast assumes that it will generate sufficient taxable income to use these credits. These credits, and their sale value, could be impacted by or become unavailable due to administrative actions of the Internal Revenue Service or the U.S. Treasury or changes in law, regulation or administration.

Problems with operations could cause TECO Energy to incur substantial costs.

Each of TECO Energy’s subsidiaries is subject to various operational risks, including accidents or equipment breakdown or failure and operations below expected levels of performance or efficiency. As operators of power generation facilities, Tampa Electric and TPS could incur problems such as the breakdown or failure of power generation equipment, transmission lines, pipelines or other equipment or processes which would result in performance below assumed levels of output or efficiency. TECO Energy’s forecast assumes normal operations and normal maintenance periods for its subsidiaries’ facilities.

The international projects and operations of TPS and TECO Ocean Shipping are subject to risks that could result in losses or increased costs.

TPS is involved in several international projects. These projects involve numerous risks that are not present in domestic projects, including expropriation, political instability, currency exchange rate fluctuations, repatriation restrictions, and regulatory and legal uncertainties. TECO Energy’s forecast assumes that TPS will manage these risks through a variety of risk mitigation measures, including specific contractual provisions, teaming with strong international and local partners, obtaining non-recourse financing and obtaining political risk insurance where appropriate.

TECO Ocean Shipping is exposed to operational risks in international ports, primarily in the form of its need to obtain suitable labor and equipment to safely discharge its cargoes in a timely manner. TECO Energy’s forecast assumes that TECO Ocean Shipping will manage these risks through a variety of risk mitigation measures, including retaining agents with local knowledge and experience in successfully discharging cargoes and vessels similar to those used.

Changes in the environmental laws and regulations to which TECO Energy’s regulated businesses are subject could increase costs or curtail activities.

TECO Energy’s businesses are subject to regulation by various governmental authorities dealing with air, water and other environmental matters. Changes in compliance requirements or the interpretation by governmental authorities of existing requirements may impose additional costs or require curtailment of some businesses’ activities.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Risk Management Infrastructure

TECO Energy and its affiliates are subject to various types of market risk in the course of daily operations, as discussed below. The company has adopted an enterprise-wide approach to the management and control of market and credit risk. Middle Office risk management functions, including credit risk management and risk control, are independent of each transacting entity (Front Office) and report to the Chief Financial Officer of TECO Energy. Front Office functions report to the various operating company presidents responsible for energy transaction activities.

The TECO Energy Risk Management Policy (Policy) governs all energy transacting activity at TECO Energy. The Policy is approved by the TECO Energy Board of Directors and administered by a Risk Authorizing Committee (RAC) that is comprised of senior management, chaired by TECO Energy’s Chief Executive Officer (CEO), and advised by the Vice President of Energy Risk Management. Within the bounds of the Policy, the RAC approves specific hedging strategies, new transaction types or products, limits, and transacting authorities. The Policy further requires that, for all merchant generation asset management activities, power sales and gas purchases must be substantially matched, and that the volume of power sales commitments is limited to the volume of owned and available generating capacity. Transaction activity is reported daily and measured against limits. For all other commodity risk management activities, derivative transaction volumes are limited to the anticipated volume for customer sales or supplier procurement activities.

The TECO Energy Authorizing Committee, directed by the CEO of TECO Energy, administers the risk management policy with respect to interest rate risk exposures. Under the policy for interest rate risk management the committee operates and oversees transaction activity. Interest rate derivative transaction activity is directly correlated to borrowing activities.

Risk Management Objectives

The Front Office is responsible for reducing and mitigating the market risk exposures which arise from the ownership of physical assets and contractual obligations, such as merchant power plants, debt instruments and firm customer sales contracts. The primary objectives of the risk management organization, the Middle Office, is to quantify, measure and monitor the market risk exposures arising from the activities of the Front Office and the ownership of physical assets. In addition, the Middle Office is responsible for enforcing the limits and procedures established under the approved risk management policies. Based on the policies approved by the company’s Board of Directors and the procedures established by the RAC, from time to time TECO Energy enters into futures, forwards, swaps and option contracts for the following purposes:

•

To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations at Tampa Electric, PGS, TECO Gas Services and Prior Energy;

•

To limit the exposure to interest rate fluctuations on debt issuances at TECO Energy and its other affiliates;

•

To limit the exposure to electricity, natural gas and fuel oil price fluctuations related to the operations of natural gas-fired and fuel oil-fired power plants at TPS; and

•

To limit the exposure to price fluctuations for physical purchases of fuel at TECO Transport.

volatility on ratepayers. For unregulated operations, the company uses derivative instruments primarily to optimize the value of physical assets, primarily including generation capacity and natural gas delivery.

Derivative and Hedge Accounting

Effective Jan. 1, 2001, TECO Energy adopted FAS 133, Accounting for Derivative Instruments and Hedging Activities, as subsequently amended and interpreted. FAS 133 requires TECO Energy and its affiliates to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value, and to reflect the changes in the fair value of those instruments as either components of other comprehensive income (OCI) or in net income, depending on the designation of those instruments. The effect of the adoption of FAS 133, at Jan. 1, 2001 on continuing operations was not material.

The accounting literature establishes specific criteria and requirements in order to apply hedge accounting. Due to the strict criteria and extensive requirements, certain derivatives do not qualify for hedge accounting, even though the derivative may efficiently and economically reduce the exposure to a particular type of risk. For accounting purposes, a derivative may only be designated as one of the following, resulting in the prescribed treatment in the financial statements:

Non-hedge: derivative must be recorded on the balance sheet at fair value; changes in the fair value of the derivative are recorded as a net gain or loss in earnings.

Cash Flow Hedge: derivative must be recorded on the balance sheet at fair value; changes in the fair value of the derivative are initially recorded in OCI; when the hedged item or anticipated hedged transaction impacts earnings, the current deferred gain or loss recorded in OCI is reclassified to earnings as an offset to the revenue or cost of the hedged item or anticipated hedged transaction.

Fair Value Hedge: derivative must be recorded on the balance sheet at fair value; changes in the fair value of the derivative are recorded in earnings; the hedged item is adjusted on the balance sheet to reflect the change in fair value from the hedge designation date; changes in the fair value of the hedged item are recorded as an offset to the change in fair value of the derivative recorded in earnings.

The designation of a derivative as either a cash flow or fair value hedge is dependent on the effectiveness of the derivative at offsetting the changes in future cash flows or fair value of the designated hedged transaction or item. The majority of the company’s derivatives are used to reduce the variability in cash flows for anticipated sales or purchases of energy as a result of subsequent price movements (cash flow hedges). For example, a derivative to purchase natural gas at a fixed price may be designated as a cash flow hedge of the variability of future cash flows associated with an anticipated purchase of natural gas for the same time period. When the forecasted physical purchases of natural gas occurs, the gain or loss on the derivative, which has been deferred in OCI, will be reclassified to the income statement to adjust the actual purchase price to the committed fixed price of natural gas under the derivative instrument. Amounts recorded in OCI related to an effective designated cash flow hedge must be reclassified to current earnings if the anticipated hedged transaction is no longer probable of occurring.

Designation of a hedging relationship requires management to make assumptions about the future probability of the timing and amount of the transaction, and the future effectiveness of the derivative instrument in offsetting the change in fair value or cash flows of the hedged item or transaction. The determination of fair value is dependent upon certain assumptions and judgments. (See Unregulated Companies section below, and Notes A and B to the Consolidated Financial Statements.)

Interest Rate Risk

TECO Energy is exposed to changes in interest rates primarily as a result of its borrowing activities. TECO Energy or its affiliates may enter into futures, swaps and option contracts, in accordance with the approved risk management policies and procedures, to moderate this exposure to interest rate changes and achieve a desired level of fixed and variable rate debt. As of Dec. 31, 2002, a hypothetical 10% increase in TECO Energy’s weighted average interest rate on its variable rate debt during 2003, as compared to 2002, would not result in a material impact on pretax earnings. Comparatively, as of Dec. 31, 2001 a hypothetical 10% increase in TECO Energy’s weighted average interest rate on its variable rate debt and required refinancings during 2002, as compared to 2001, would have resulted in an estimated $3.2 million decrease in pretax earnings. These amounts were determined based on the variable rate obligations existing on the indicated date at TECO Energy and its subsidiaries. The reduction of the sensitivity to hypothetical interest rate movements is due to the amount of variable rate debt outstanding and substantially lower debt maturities. Due to the uncertainty of future events, as discussed in the Investment Considerations section, and management’s responses to those events, the sensitivities assume no changes to TECO Energy’s financing structure. A hypothetical 10% change in interest rates would increase the fair value of long-term debt 5.6 percent at Dec. 31, 2002. A hypothetical 10% change in interest rates would not have a significant impact on the estimated fair value of TECO Energy’s long-term debt at Dec. 31, 2001. (See Financing Activity section, and Notes E and F to the Consolidated Financial Statements.)

Credit Risk

TECO Energy has adopted a rigorous process for the establishment of new trading counterparties. This process includes an evaluation of each counterparty’s financial statements with particular attention paid to liquidity and capital

resources, establishment of counterparty-specific credit limits, optimization of credit terms, and execution of standardized enabling agreements. TECO Energy’s Credit Guidelines require transactions with counterparties below investment grade to be collateralized. The Credit Guidelines are administered and monitored within the Middle Office, independent of the Front Office.

Financial instability and significant uncertainties relating to liquidity in the entire merchant energy sector have increased the perceived credit risk. Credit exposures for merchant generation activities are calculated, compared to limits and reported to management on a daily basis. Contracts with different legal entities of the same counterparty are consolidated and managed as appropriate, considering the legal structure and any netting agreements in place. Below is a summary of TECO Energy’s credit risk exposure on energy contracts related to merchant generation activities at Dec. 31, 2002.

(millions) Rating(1)	Exposure Before Credit Collateral(2)		Credit Collateral(3)		Net Exposure		Number of Counterparties >10%(4)	Net Exposure Counterparties >10%(4)
Investment grade	$	13.1		—	$	13.1	4	$	12.7
Split rating		—		—		—	—		—
Non-investment grade		—		—		—	—		—
No external ratings (internally rated)
Investment grade		<0.1		—		<0.1	—		—
Non-investment grade		—		2.5		—	—		—

Total	$	13.1	$	2.5	$	13.1	4	$	12.7

(1)

Ratings are principally determined based on publicly available credit ratings, as determined by independent ratings agencies. If the counterparty has provided a guarantee by a higher rated entity, the assigned rating is that of the guarantor. Included in Investment grade are those counterparties with a minimum S&P or Fitch’s rating of BBB- or higher and a Moody’s rating of Baa3 or higher.

(2)

Exposure before credit collateral includes the fair value of net energy contract assets for open positions and the net account receivable for realized energy contracts. Exposures are offset by a legal counterparty where legally enforceable netting and setoff arrangements are in place.

(3)

Credit collateral is required from time-to-time based on contractual provisions and may generally include cash deposits and letters of credit. At Dec. 31, 2002, credit collateral was required from two non-investment grade counterparties. However, TECO EnergySource was not exposed to these counterparties based on the unrealized fair value of the open energy contracts at Dec. 31, 2002.

(4)

The number of counterparties that individually, after considering legally enforceable netting arrangements, represent a significant concentration of credit risk (i.e., more than 10% of the total credit exposure) at TECO EnergySource. Also, the combined exposure, less credit collateral, if any, of each significant concentration.

Commodity Risk

TECO Energy and its affiliates face varying degrees of exposure to commodity risks—including coal, natural gas, fuel oil and other energy commodity prices. Any changes in prices could affect the prices these businesses charge, their operating costs and the competitive position of their products and services. The company assesses and monitors risk using a variety of state-of-the-art measurement tools. Management uses different risk measurement and monitoring tools based on the degree of exposure of each operating company to commodity risk.

Regulated Utilities

At Tampa Electric, fuel costs used for generation are currently most affected by the cost of coal. Future fuel costs will be impacted by the cost of natural gas, in addition to coal, as the repowering of the Gannon Station is completed. (See the Environmental Compliance section.) PGS is primarily subject to costs for purchased gas and pipeline capacity. Increasing costs for the regulated utilities impact their competitive position in the marketplace versus other energy sources and suppliers.

Currently, Tampa Electric and PGS are subject to relatively little commodity price risk exposure. This is primarily due to the fact that commodity price increases due to changes in market conditions for fuel, purchased power and natural gas are recovered through cost recovery clauses, with no anticipated effect on earnings. Commodity price risk is mitigated by the use of long-term fuel supply agreements, prudent operation of plant facilities to reduce the reliance on purchased power, and derivative instruments designated as cash flow hedges of anticipated purchases of natural gas. At Dec. 31, 2002 and 2001, a change in commodity prices would not have a material impact on earnings for Tampa Electric or PGS.

Unregulated Companies

Most of the unregulated subsidiaries at TECO Energy are subject to significant commodity risk. These include TECO Coal, TECO Transport, TECO Gas Services, Prior Energy and TPS. The unregulated companies do not speculate using derivative instruments. However, not all derivative instruments receive hedge accounting treatment due to the strict requirements and narrow applicability of the accounting literature to dynamic transactions, as discussed above in the Derivative and Hedge Accounting section.

TECO Coal is exposed to commodity price risk through coal sales as a part of its daily operations. Fixed price sales agreements are used, where possible and economical, to mitigate the variability in coal prices. At Dec. 31, 2002 and 2001, a hypothetical 10% change in the average annual market price of coal for each year would have resulted in a decrease to pretax earnings of approximately $5 million and $15 million, respectively.

Fuel price risk exists at TECO Transport as a result of periodic purchases of diesel fuel. Haulage and freight agreements often include fuel price adjustments to transfer the risk of market fuel price movements to the customer. TECO Transport also utilizes derivative instruments to reduce the risk of price variability for anticipated fuel purchases in excess of purchases subject to fuel adjustment clauses. As of Dec. 31, 2002, substantially all of the projected fuel price risk for 2003 was removed via price adjustment clauses and a derivative instrument. As a result, a hypothetical 10% change in the average annual market price of fuel would not result in a material impact on pretax earnings as of Dec. 31, 2002 and would have resulted in an impact to pretax earnings of approximately $1 million as of Dec. 31, 2001.

Prior Energy and TECO Gas Services are exposed to variability in natural gas prices as a result of their commitments to purchase from suppliers and deliver physical natural gas to customers. Prior Energy and TECO Gas Services generally enter into fixed price agreements to provide procurement and fuel optimization services to customers. At the same time, derivative instruments and fixed price purchase agreements from suppliers are used to meet customers’ requirements. As a result, a hypothetical change in natural gas prices would not have had a material impact for such operations as of Dec. 31, 2002 and 2001.

Prior Energy also provides hedge management and storage solutions for customers. Derivative instruments are carefully used to reduce or eliminate natural gas price risk associated with these activities. As of Dec. 31, 2002 and 2001, a hypothetical 10% change in natural gas prices would not result in a material impact on earnings.

For TPS, results of operations are impacted primarily by changes in the market prices for electricity and natural gas. The profitability of merchant power plants is heavily dependent on the spread between electric and gas prices (spark spread) in the markets they serve.

The spark spread calculates the relative profitability of converting gas into electricity, which exists as the best indicator of a gas-fired plant’s profitability. The variable cost of producing electricity is primarily a function of gas commodity prices and the heat rate of the plant. The heat rate is the measure of efficiency in converting the input fuel into electricity. When the conversion price equals the market price, the spark spread would be zero. A power plant operating at this level would theoretically break even with respect to variable costs.

Wholesale power prices are set by the market assuming a cost for the input energy and conversion efficiency, but the fixed costs are not necessarily reflected in the market-observed spark spread. TPS uses derivative instruments to reduce the commodity price risk exposure of the merchant plants. The commodity price risk of each plant is managed on both a portfolio and asset-specific basis. The following table summarizes the impact of a hypothetical 10% change in commodity prices on the fair value of merchant energy derivative contracts at Dec. 31, 2002 and Dec. 31, 2001.

Sensitivity of the Fair Value of Merchant Energy Derivative Contracts

(millions)	Dec. 31, 2002			Dec. 31, 2001
Change in Fair Value due to a 10%(1):
Decrease in natural gas prices	$	(16.9	)	$	(4.0	)
Increase in electricity prices		(24.4	)		—	(2)
Increase in electricity and natural gas prices		(7.5	)		—	(2)

(1)

Reflects the fair value associated with merchant energy derivative contracts only. The change shown for the contracts due to price movements would be more than offset by a change in the fair value of the underlying physical plant assets.

(2)

No material impact.

Below is a summary of the percentage of merchant plant output and fuel requirements hedged.

Estimated Merchant Plant Hedging Information

		2003			2004
Forecasted plant output and fuel requirements hedged		37	%		15	%

The following tables summarize the changes in and the fair value balances of energy derivative assets (liabilities) for the years ended Dec. 31, 2001 and 2002.

Changes in Fair Value of Energy Derivatives (millions)

Net fair value of derivatives as of Dec. 31, 2000	$	(19.0	)
Net change in unrealized fair value of derivatives		(29.2	)
Changes in valuation techniques and assumptions		—
Realized net settlement of derivatives		21.1

Net fair value of derivatives as of Dec. 31, 2001		(27.1	)
Net change in unrealized fair value of derivatives		4.7
Changes in valuation techniques and assumptions		—
Realized net settlement of derivatives		30.8

Net fair value of derivatives as of Dec. 31, 2002	$	8.4

Roll-Forward of Energy Derivatives Net Assets (Liabilities) (millions)

Total energy contracts net assets (liabilities) as of Dec. 31, 2000	$	(19.0	)
Change in fair value of net derivative assets (liabilities):
Recorded in OCI		(1.2	)
Recorded in earnings		21.1
Net option premium payments		2.3
Net purchase (sale) of existing contracts		(30.3	)

Total energy contracts net assets (liabilities) as of Dec. 31, 2001		(27.1	)
Change in fair value of net derivative assets (liabilities):
Recorded in OCI		4.7
Recorded in earnings		30.8
Net option premium payments		—
Net purchase (sale) of existing contracts		—

Net fair value of derivatives as of Dec. 31, 2002	$	8.4

When available, the company uses quoted market prices to record the fair value of energy derivative contracts. However, certain energy derivative contracts are not exchange-traded, but rather, are traded in the over-the-counter (OTC) market, through multiple-party on-line trading platforms, or in the bilateral market. TECO Energy uses industry-accepted valuation techniques based on pricing models or matrix pricing for energy derivative contracts when third-party price data is infrequent or not available. Prices, inputs, assumptions and the results of valuation techniques are validated by the Middle Office, independently of the Front Office, on a daily basis. Significant inputs and assumptions used by the company to determine the fair value of energy derivative contracts are: 1) the physical delivery location of the commodity; 2) the correlation between different basis points and/or different commodities; 3) rational, economic behavior in the markets and by counterparties; 4) on- and off-peak curve shapes and correlations; 5) observed market information; and 6) volatility forecasts for and between commodities. Mathematical approaches are applied on a frequent basis to validate and corroborate the results of valuation calculations.

Below is a summary table of sources of fair value, by maturity period, for energy derivative contracts at Dec. 31, 2002.

Maturity and Source of Energy Derivative Contracts Net Assets(Liabilities) at Dec. 31, 2002

Contracts Maturing in	2003			2004			Total fair Value
Source of Fair Value (millions)
Actively quoted prices	$	8.7		$	0.1		$	8.8
Other external sources(1)		(0.3	)		(0.1	)		(0.4	)
Model Prices(2)		—			—			—

Total	$	8.4		$	—		$	8.4

(1)

Information from external sources includes information obtained from over-the-counter brokers, industry price services or surveys and multiple-party on-line platforms.

(2)

Model prices are used for determining the fair value of energy derivatives where price quotes are infrequent or the market is illiquid. Significant inputs to the models are derived from market observable data and actual historical experience.

For all unrealized energy derivative contracts, the valuation is an estimate based on the best available information. Actual cash flows could be materially different from the estimated value upon maturity.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

TECO ENERGY, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

		Page No.
Report of Independent Certified Public Accountants		65

Consolidated Balance Sheets, Dec. 31, 2002 and 2001		66-67

Consolidated Statements of Income for the years ended Dec. 31, 2002, 2001 and 2000		68

Consolidated Statements of Comprehensive Income		69

Consolidated Statements of Cash Flows for the years ended Dec. 31, 2002, 2001 and 2000		70

Consolidated Statements of Equity for the years ended Dec. 31, 2002, 2001 and 2000		71

Notes to Consolidated Financial Statements		72-103

Financial Statement Schedule II—Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2002, 2001 and 2000		130

Signatures		132

Certifications		133-134

All other financial statement schedules have been omitted since they are not required, are inapplicable or the required information is presented in the financial statements or notes thereto.

Report of Independent Certified Public Accountants

To the Board of Directors and Shareholders of TECO Energy, Inc.,

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of TECO Energy, Inc. and its subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in the Notes C and B to the Consolidated Financial Statements, the Company adopted the provisions of Financial Accounting Standard 142, Goodwill and Other Intangible Assets on January 1, 2002 and Financial Accounting Standard 133, Accounting for Derivative Instruments and Hedging on January 1, 2001, respectively.

/s/ PricewaterhouseCoopers LLP

Tampa, Florida

January 22, 2003 except for the information in Note U as to which the date is January 30, 2003.

TECO ENERGY, INC.

Consolidated Balance Sheets

Assets (millions)

Dec. 31,	2002			2001
Current assets
Cash and cash equivalents	$	411.1		$	108.5
Restricted cash		1.6			1.6
Receivables, less allowance for uncollectibles of $6.6 million and $7.1 million at Dec. 31, 2002 and 2001, respectively		422.7			358.6
Current notes receivable		235.1			92.7
Inventories, at average cost
Fuel		113.7			87.3
Materials and supplies		96.1			83.2
Prepayments and other current assets		42.9			44.4

Total current assets		1,323.2			776.3

Property, plant and equipment
Utility plant in service
Electric		5,054.4			4,861.1
Gas		746.7			699.4
Construction work in progress		1,556.8			897.0
Other property		857.4			865.1

Property, plant and equipment, at original cost		8,215.3			7,322.6
Accumulated depreciation		(2,751.3	)		(2,572.0	)

		5,464.0			4,750.6
Property held for sale (net)		—			87.6
Total property, plant and equipment (net)		5,464.0			4,838.2

Other assets
Other investments		845.3			210.4
Investment in unconsolidated affiliates		149.2			172.9
Goodwill		193.7			165.8
Deferred income taxes		340.2			242.0
Regulatory assets		163.2			198.3
Deferred charges and other assets		159.0			159.5

Total other assets		1,850.6			1,148.9

Total assets	$	8,637.8		$	6,763.4

The accompanying notes are an integral part of the consolidated financial statements.

TECO ENERGY, INC.

Consolidated Balance Sheets

Liabilities and Capital (millions)

Dec. 31,	2002			2001
Current liabilities
Long-term debt due within one year	$	127.1		$	788.8
Notes payable		360.5			638.9
Accounts payable		377.4			267.4
Current derivative liability		3.9			33.5
Customer deposits		94.6			86.3
Interest accrued		49.8			35.6
Taxes accrued		95.9			71.7

Total current liabilities		1,109.2			1,922.2

Other liabilities
Deferred income taxes		495.0			498.7
Investment tax credits		27.5			32.3
Regulatory liabilities		98.1			106.2
Deferred credits and other liabilities		322.9			189.9
Long-term debt, less amount due within one year		3,324.3			1,842.5

Total other liabilities		4,267.8			2,669.6

Preferred securities
Company preferred securities		649.1			200.0

Capital
Common equity (400 million shares authorized; 175.8 million and 139.6 million outstanding at Dec. 31, 2002 and 2001, respectively)		175.8			139.6
Additional paid in capital		1,094.5			600.7
Retained earnings		1,413.7			1,298.0
Accumulated other comprehensive (loss) income		(41.2	)		(22.4	)

Common equity		2,642.8			2,015.9
Unearned compensation		(31.1	)		(44.3	)

Total capital		2,611.7			1,971.6

Total liabilities and capital	$	8,637.8		$	6,763.4

The accompanying notes are an integral part of the consolidated financial statements.

TECO ENERGY, INC.

Consolidated Statements of Income

(millions, except per share amounts)

Year Ended Dec. 31,	2002			2001			2000
Revenues
Regulated electric and gas (includes franchise fee and gross receipts taxes of $73.8 million in 2002, $71.1 million in 2001 and $59.7 million in 2000)	$	1,867.0		$	1,733.0		$	1,635.9
Unregulated		808.8			755.1			587.2

Total revenues		2,675.8			2,488.1			2,223.1

Expenses
Regulated operations
Fuel		312.7			218.2			201.2
Purchased power		202.3			144.7			124.5
Cost of natural gas sold		148.9			186.4			157.0
Other		273.8			250.0			247.1
Other operations		710.4			689.8			546.9
Maintenance		162.1			151.3			140.0
Depreciation		303.4			288.2			258.0
Taxes, other than income		173.2			161.3			147.9

Total expenses		2,286.8			2,089.9			1,822.6

Income from operations		389.0			398.2			400.5

Other income (expense)
Allowance for other funds used during construction		24.9			6.6			1.6
Other income (expense)		62.4			38.6			13.9
Loss on debt refinancing		(34.1	)		—			—
Earnings from equity investments		(6.0	)		6.7			7.7

Total other income (expense)		47.2			51.9			23.2

Interest charges
Interest expense		147.1			164.0			167.6
Distribution on preferred securities		38.9			17.0			—
Allowance for borrowed funds used during construction		(9.6	)		(2.6	)		(0.7	)

Total interest charges		176.4			178.4			166.9

Income before provision for income taxes		259.8			271.7			256.8
Provision (benefit) for income taxes		(38.4	)		(2.1	)		29.3

Net income from continuing operations		298.2			273.8			227.5

Discontinued operations
Income from discontinued operations		26.1			21.9			12.6
Income tax benefit		(5.8	)		(8.0	)		(10.8	)

Total discontinued operations		31.9			29.9			23.4

Net income	$	330.1		$	303.7		$	250.9

Average common shares outstanding during year
—Basic		153.2			134.5			125.9
—Diluted		153.3			135.4			126.3

Earnings per average common share outstanding
From continuing operations
—Basic	$	1.95		$	2.04		$	1.81
—Diluted	$	1.95		$	2.02		$	1.79
Net income
—Basic	$	2.15		$	2.26		$	1.99
—Diluted	$	2.15		$	2.24		$	1.97

The accompanying notes are an integral part of the consolidated financial statements.

TECO ENERGY, INC.

Consolidated Statements of Comprehensive Income

(millions, except per share amounts)
Year Ended Dec. 31,	2002			2001			2000
Net income	$	330.1		$	303.7		$	250.9

Other comprehensive (loss) income, net of tax
Foreign currency translation adjustments		(1.2	)		—			—
Net unrealized losses on cash flow hedges		(13.2	)		(19.2	)		—
Minimum pension liability adjustments		(4.4	)		0.3			2.0

Other comprehensive (loss) income, net of tax		(18.8	)		(18.9	)		2.0

Comprehensive income	$	311.3		$	284.8		$	252.9

The accompanying notes are an integral part of the consolidated financial statements.

TECO ENERGY, INC.

Consolidated Statements of Cash Flows

(millions, except per share amounts)
Year Ended Dec. 31,	2002			2001			2000
Cash flows from operating activities
Net income	$	330.1		$	303.7		$	250.9
Adjustments to reconcile net income to net cash from operating activities:
Depreciation		303.4			288.2			258.0
Deferred income taxes		(96.5	)		(102.9	)		(77.6	)
Investment tax credits, net		(4.8	)		(4.9	)		(4.8	)
Allowance for funds used during construction		(34.5	)		(9.2	)		(2.3	)
Amortization of unearned compensation		13.9			9.7			9.2
Gain on asset sales, pretax		(15.1	)		—			(13.6	)
Equity in earnings of unconsolidated affiliates		15.3			(3.1	)		(7.6	)
Asset valuation adjustment, pretax		14.1			11.1			14.2
Deferred recovery clause		72.2			(19.0	)		(68.7	)
Refund to customers		(6.4	)		—			(13.2	)
Receivables, less allowance for uncollectibles		(64.1	)		57.1			(95.5	)
Inventories		(39.4	)		(22.8	)		7.5
Taxes accrued		24.1			16.4			17.6
Interest accrued		14.2			(6.3	)		25.5
Accounts payable		98.3			(51.3	)		42.6
Other		30.9			36.0			44.1

Cash flows from operating activities		655.7			502.7			386.3

Cash flows from investing activities
Capital expenditures		(1,065.2	)		(965.9	)		(688.4	)
Allowance for funds used during construction		34.5			9.2			2.3
Purchase of minority interest		(9.9	)		—			(52.6	)
Purchase of business		—			(315.8	)		(31.3	)
Net proceeds from sales of assets		103.3			43.2			61.3
Investment in unconsolidated affiliates		(7.6	)		27.6			(7.7	)
Other non-current investments		(715.6	)		95.7			(333.4	)

Cash flows from investing activities		(1,660.5	)		(1,106.0	)		(1,049.8	)

Cash flows from financing activities
Dividends		(215.8	)		(184.2	)		(167.4	)
Common stock		572.6			348.4			18.3
Purchase of treasury stock		—			—			(29.9	)
Proceeds from long-term debt		1,758.4			1,255.9			394.9
Repayment of long-term debt		(949.7	)		(236.5	)		(145.6	)
Net increase (decrease) in short-term debt		(278.4	)		(570.0	)		395.3
Issuance of preferred securities		435.6			—			200.0
Equity contract adjustment payments		(15.3	)		—			—

Cash flows from financing activities		1,307.4			613.6			665.6

Net increase in cash and cash equivalents		302.6			10.3			2.1
Cash and cash equivalents at beginning of year		108.5			98.2			96.1

Cash and cash equivalents at end of year	$	411.1		$	108.5		$	98.2

Supplemental disclosure of cash flow information
Cash paid during the year for
Interest (net of amounts capitalized)	$	160.2		$	178.1		$	166.7
Income taxes	$	71.9		$	52.4		$	83.9

The accompanying notes are an integral part of the consolidated financial statements.

TECO ENERGY, INC.

Consolidated Statements of Common Equity

(millions)	Shares(1)		Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Unearned Compensation			Total Common Equity
Balance, Dec. 31, 1999	126.7		$	132.1	$	368.9		$	(114.8	)	$	1,091.8		$	(5.5	)	$	(54.7	)	$	1,417.8
Net income for 2000												250.9									250.9
Other comprehensive income, after tax															2.0						2.0
Common stock issued	1.2			1.2		26.8												(3.9	)		24.1
Treasury shares purchased	(1.6	)							(29.9	)											(29.9	)
Cash dividends declared												(167.4	)								(167.4	)
Amortization of unearned compensation																		9.2			9.2
Tax benefits–ESOP dividends and stock options						1.6						1.8									3.4
Performance shares																		(3.2	)		(3.2	)

Balance, Dec. 31, 2000	126.3			133.3		397.3			(144.7	)		1,177.1			(3.5	)		(52.6	)		1,506.9
Net income for 2001												303.7									303.7
Other comprehensive (loss) income, after tax															(18.9	)					(18.9	)
Common stock issued	13.3			6.3		203.2			144.7									(5.8	)		348.4
Cash dividends declared												(184.2	)								(184.2	)
Amortization of unearned compensation																		9.7			9.7
Tax benefits–ESOP dividends and stock options						0.2						1.4									1.6
Performance shares																		4.4			4.4

Balance, Dec. 31, 2001	139.6			139.6		600.7			—			1,298.0			(22.4	)		(44.3	)		1,971.6
Net income for 2002												330.1									330.1
Other comprehensive (loss) income, after tax															(18.8	)					(18.8	)
Common stock issued	36.2			36.2		544.4												(8.0	)		572.6
Cash dividends declared												(215.8	)								(215.8	)
Amortization of unearned compensation																		13.9			13.9
Convertible preferred stock – present value of contract adjustment payments						(53.1	)														(53.1	)
Tax benefits–
ESOP dividends and stock options						2.5						1.4									3.9
Performance shares																		7.3			7.3

Balance, Dec. 31, 2002	175.8		$	175.8	$	1,094.5		$	—		$	1,413.7		$	(41.2	)	$	(31.1	)	$	2,611.7

The accompanying notes are an integral part of the consolidated financial statements.

(1)

TECO Energy had 400 million shares of $1 par value common stock authorized in 2002, 2001 and 2000.

TECO ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A. Summary of Significant Accounting Policies

The significant accounting policies for both utility and diversified operations are as follows:

Principles of Consolidation

The consolidated financial statements include the accounts of TECO Energy, Inc. (TECO Energy or the company) and its wholly-owned subsidiaries.

The equity method of accounting is used to account for investments in partnership arrangements in which TECO Energy or its subsidiary companies do not have majority ownership or exercise control.

The proportional share of expenses, revenues and assets reflecting TECO Coalbed Methane’s undivided interest in joint venture property is included in the consolidated financial statements. Results of operations for TECO Coalbed Methane are included in discontinued operations.

All significant intercompany balances and intercompany transactions have been eliminated in consolidation.

The use of estimates is inherent in the preparation of financial statements in accordance with generally accepted accounting principles.

Cash Equivalents

Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.

Investments in Unconsolidated Affiliates

Investments in unconsolidated affiliates are accounted for using the equity method of accounting. At Dec. 31, 2002, these investments included TECO Propane Ventures’ (TPV) 38 percent ownership interest in US Propane, TECO Power Services’ (TPS) 24 percent ownership interest in Empresa Eléctrica de Guatemala, S.A. (EEGSA), the Guatemalan electric utility, TPS’ 50 percent voting interest in the TECO-Panda Generating Company, L.P. (TPGC), TPS’ 50 percent ownership interest in the Hamakua Power Station in Hawaii, TECO Energy Services’ 50 percent ownership interest in a chiller plant project, TECO Partners’ 65 percent ownership interest in Litestream Technologies, a fiber optic cable project, and TECO Properties’ 50 percent ownership interest in four real estate projects (See Note T). At Dec. 31, 2001, the investment in unconsolidated affiliates included the US Propane, EEGSA, TPGC, Hamakua and real estate investments.

Summary financial information for TPGC, a development stage enterprise, as of Dec. 31, 2002 and 2001 is presented in the following table. Results from operations were primarily attributable to financing and general administrative costs associated with construction activities.

Summary Financial Information for TPGC

(millions) Dec. 31,	2002			2001
Current assets	$	53.5		$	102.6
Non-current assets	$	3,114.7		$	1,854.1
Current liabilities	$	596.9		$	372.8
Non-current liabilities	$	2,790.6		$	1,686.6

(millions) For the year ended Dec. 31,	2002			2001
Net revenues	$	0.7		$	0.5
Operating loss	$	(22.0	)	$	(5.4	)
Loss available for allocation to partners	$	(22.0	)	$	(5.4	)

Other Investments

Other investments, which include longer-term passive investments, at Dec. 31, 2002 and 2001 were as follows:

Other Investments

(millions) Dec. 31,	Rate		Due Date	2002		2001
Notes receivable from:
Panda Energy(1)	14.00	%	1/3/03	$	137.0	$	92.7
Energeticke Centrum Kladno	6.00	%	10/31/10		1.4		—
Mosbacher Power Partners L.P.	12.00	%	5/16/02		—		13.1
Mosbacher Power Partners L.P.	9.00	%	8/1/08		13.7		21.1
Mosbacher Power Partners L.P.	12.00	%	5/16/02		—		6.2
EEGSA	6.81	%(2)	9/11/07		11.1		10.9
TECO-Panda Generating Company, L.P.	7.79	%(2)	11/30/04		369.5		37.5
TECO-Panda Generating Company, L.P.	6.58	%(2)	11/30/04		426.3		86.7
Municipal Gas Authority of Georgia(3)	1.38	%	3/31/03		98.1		—
Investment in Energy Center Kladno
Generating (ECKG)(4)	—		—		13.6		18.2
Continuing Investments in Leveraged Leases	—		—		9.4		15.6
Other investments	—		—		0.3		1.1

					1,080.4		303.1
Current notes receivable					235.1		92.7

Other non-current investments				$	845.3	$	210.4

(1)

On Jan. 3, 2003, this note receivable converted to an ownership interest (see Note N).

(2)

Current rate at Dec. 31, 2002.

(3)

Received payment of this note receivable on Jan. 30, 2003 (see Note U).

(4)

13.35% ownership interest in an electric generating power project in the Czech Republic.

These financial investments have no quoted market prices and, accordingly, a reasonable estimate of fair market value could not be made without incurring excessive costs. However, the company believes by reference to stated interest rates and security description, the fair value of these assets would not differ significantly from the carrying value.

Deferred Credits and Other Liabilities

Other deferred credits primarily include the accrued post-retirement benefit liability, the pension liability, deferred gains and the liability for future contract adjustment payments related to the mandatorily convertible equity securities.

Revenue Recognition

TECO Energy recognizes revenues in accordance with the Securities and Exchange Commission’s Staff Accounting Bulletin (SAB) 101, Revenue Recognition in Financial Statements. The criteria outlined in SAB 101 are that a) there is persuasive evidence that an arrangement exists; b) delivery has occurred or services have been rendered; c) the fee is fixed and determinable; and d) collectibility is reasonably assured. Except as discussed below, TECO Energy and its subsidiaries recognize revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer. Revenues for any financial or hedge transactions that do not result in physical delivery are reported on a net basis.

The regulated utilities’ (Tampa Electric Company and Peoples Gas System) retail businesses and the prices charged to customers are regulated by the Florida Public Service Commission (FPSC). Tampa Electric’s wholesale business is regulated by the Federal Energy Regulatory Commission (FERC). As a result, the regulated utilities qualify for the application of Financial Accounting Standard No. (FAS) 71, Accounting for the Effects of Certain Types of Regulation. See Note D for a discussion of the applicability of FAS 71 to the company. Revenues for certain transportation services at TECO Transport are recognized using the percentage of completion method, which includes estimates of the distance traveled and/or the time elapsed, compared to the total estimated contract.

Revenues for long-term engineering or construction-type contracts at TECO Energy Services (formerly TECO BGA and BCH Mechanical) are recognized on a percentage of completion basis, which includes estimates of the total costs for the project compared to the estimated work progress already completed for the contract. Each month, revenue recognition and realized profit are adjusted to reflect only the percentage of the estimated costs that have been completed.

Revenues for energy marketing operations at Prior Energy and TECO Gas Services are presented on a net basis in accordance with Emerging Issues Task Force No. (EITF), 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent and EITF 02-3, Recognition and Reporting of Gains and Losses on Energy Trading Contracts Under Issues No. 98-10 and 00-17, to reflect the nature of the contractual relationships with customers and suppliers. As a result, costs netted against revenues were $539.4 million, $105.5 million and $28.4 million, respectively, for 2002, 2001 and 2000.

Revenues and Fuel Costs

Revenues include amounts resulting from cost recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline capacity and conservation costs for Peoples Gas System (PGS). These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over-recovery or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as deferred credits, and under-recoveries of costs are recorded as deferred charges.

In 1994, Tampa Electric bought out a long-term coal supply contract which would have expired in 2004 for a lump sum payment of $25.5 million. In February 1995, the FPSC authorized the recovery of this buy-out amount plus carrying costs through the Fuel and Purchased Power Cost Recovery Clause over the 10-year period beginning Apr. 1, 1995. In each of the years 2002, 2001 and 2000, $2.7 million of buy-out costs were amortized to expense.

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed.

The regulated utilities accrue base revenues for services rendered but unbilled to provide a closer matching of revenues and expenses.

Tampa Electric’s objectives of stabilizing prices from 1996 through 1999 and securing fair earnings opportunities during this period were accomplished through a series of agreements entered into in 1996 with Florida’s Office of Public Counsel (OPC) and the Florida Industrial Power Users Group, which were approved by the FPSC. Prior to these agreements, the FPSC approved a plan submitted by Tampa Electric to defer certain 1995 revenues.

In general, under these agreements Tampa Electric was allowed to defer revenues in 1995 and 1996 during the construction of Polk Unit 1 and recognize these revenues in 1997 and 1998 after commercial operation of the unit. Other components of the agreements were a base rate freeze through 1999 and refunds to customers totaling $50 million during the period October 1996 through December 1998 while Tampa Electric was allowed recovery of the capital costs incurred for the Polk Unit 1 project.

In October 2000, the FPSC staff recommended a refund of $6.1 million for the final year of the agreements. OPC objected to certain interest expenses recognized in 1999 that were associated with prior years’ tax positions and used to calculate the amount to be refunded. Following a review by the FPSC staff, the FPSC agreed in December 2000 that the original $6.1 million was to be refunded to customers. In February 2001, OPC protested the FPSC’s decision. The FPSC held hearings on the issue in August 2001 and upheld its original decision. In January 2002, the OPC filed a motion with the FPSC asking for reconsideration of its decision, alleging the FPSC relied on erroneous information. This was not granted and Tampa Electric made refunds associated with 1999 earnings in 2002. Over the terms of the agreements, the company refunded in total about $69 million.

On June 27, 2002, PGS filed a petition with the FPSC to increase its service rates. The requested rates would have resulted in a $22.6 million annual base revenue increase, reflecting a ROE midpoint of 11.75 percent.

On the date of the FPSC hearing, PGS agreed to a settlement with all parties involved, and a final FPSC order was granted on Dec. 17, 2002. PGS received authorization to increase annual base revenues by $12.05 million. The new rates allow for an ROE range of 10.25 to 12.25 percent with an 11.25 percent midpoint ROE and a capital structure with 57.43 percent equity. The increase went into effect on Jan. 16, 2003.

Purchased Power

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. For the years ended Dec. 31, 2002, 2001 and 2000, Tampa Electric purchased power of $202.3 million, $144.7 million and $124.5 million, respectively. These purchased power costs are recoverable through an FPSC-approved cost recovery clause.

TPS, through its wholly-owned subsidiary, Hardee Power Partners (Hardee), has agreements with Seminole Electric Cooperative and Tampa Electric to supply all the power and capacity of its Hardee Power Station for 20 years beginning in 1993. Under the Seminole agreement, Hardee agreed to supply Seminole with an additional 145 megawatts of capacity during the first 10 years of the contract, which ended on Dec. 31, 2002. This additional capacity was purchased from Tampa Electric’s Big Bend Unit 4 for resale to Seminole. To meet other firm commitment contracts, TPS’ merchant plants may also purchase power from time to time. Total unregulated purchased power for 2002, 2001 and 2000 was $51.3 million, $34.0 million and $30.1 million, respectively.

Planned Major Maintenance

TECO Energy accounts for planned maintenance projects by expensing the costs as incurred. Planned major maintenance projects that do not increase the overall life or value of the related assets are expensed. When the major maintenance materially increases the life or value of the underlying asset, the cost is capitalized. While normal maintenance outages covering various components of the plants generally occur on at least a yearly basis, major overhauls occur less frequently.

Tampa Electric expenses major maintenance costs as incurred. Concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with FPSC and FERC regulations.

At TPS, each of the San Jose and Alborada plants in Guatemala has a long-term power purchase agreement (PPA) with EEGSA. A major maintenance revenue recovery component is implicit in the capacity payment portion of the PPA for each plant. Accordingly, a portion of each monthly fixed capacity payment is deferred to recognize the portion that reflects recovery of future planned major maintenance expenses. Actual maintenance costs are expensed when incurred with a like amount of deferred recovery revenue recognized at the same time. All other TPS operating projects expense major maintenance costs when incurred.

Depreciation

The original cost of utility plant retired or otherwise disposed of and the cost of removal less salvage are charged to accumulated depreciation. The implementation of FAS 143, Accounting for Asset Retirement Obligations in 2003 will result in the carrying amount of long-lived assets being increased, and this adjusted capitalized amount depreciated over the useful life of the asset. (See Note T – Accounting for Asset Retirement Obligations.)

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

TECO Coal and TECO Transport incur most of TECO Energy’s total excise taxes, which are accrued as an expense and reconciled to the actual cash payment of excise taxes. As general expenses, they are not specifically recovered through revenues. Excise taxes paid by the regulated utilities are not material and are expensed when incurred.

The regulated utilities are allowed to recover certain costs incurred from customers through prices approved by the regulatory process. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Statement of Income. These amounts totaled $73.8 million, $71.1 million and $59.7 million, respectively, for 2002, 2001 and 2000. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statement of Income in Taxes, other than income. For 2002, 2001 and 2000 these totaled $73.7 million, $71.0 million and $59.8 million, respectively.

Allowance for Funds Used During Construction (AFUDC)

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. The rate was 7.79% for 2002, 2001 and 2000. Total AFUDC for 2002, 2001 and 2000 was $34.5 million, $9.2 million, and $2.3 million, respectively. The base on which AFUDC is calculated excludes construction work in progress which has been included in rate base.

Interest Capitalized

Interest costs for the construction of non-utility facilities are capitalized and depreciated over the service lives of the related property. TECO Energy capitalized $63.2 million, $23.0 million and $6.5 million of interest costs in 2002, 2001 and 2000, respectively.

Deferred Income Taxes

TECO Energy utilizes the liability method in the measurement of deferred income taxes. Under the liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at current tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates.

Investment Tax Credits

Investment tax credits have been recorded as deferred credits and are being amortized to income tax expense over the service lives of the related property.

Asset Impairments

Effective Jan. 1, 2002, TECO Energy and its subsidiaries adopted FAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which supersedes FAS 121, Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of. FAS 144 addresses accounting and reporting for the impairment or disposal of long-lived assets, including the disposal of a segment of a business.

The company periodically assesses whether there has been a permanent impairment of its long-lived assets and certain intangibles held and used by the company, in accordance with FAS 144, and prior to 2002 with FAS 121.

TECO Energy recorded after-tax charges of $8.8 million, $7.2 million and $9.0 million in 2002, 2001 and 2000, respectively, to adjust asset valuations (see Note L).

Reporting on the Costs of Start-up Activities

In 1998, the American Institute of Certified Public Accountants (AICPA) issued Statement of Position (SOP) 98-5, Reporting on the Costs of Start-up Activities. It requires costs of start-up activities and organization costs to be expensed as incurred. Start-up activities are broadly defined as those one-time activities related to events such as opening a new facility, conducting business in a new territory and organizing a new entity. Some costs, such as the costs of acquiring or constructing long-lived assets and bringing them into service, are not subject to SOP 98-5. Start-up costs, as defined by SOP 98-5, are expensed as incurred.

Foreign Operations

The functional currency of the company’s foreign investments is primarily the U.S. dollar. Transactions in the local currency are remeasured to the U.S. dollar for financial reporting purposes. The aggregate remeasurement gains or losses included in net income in 2002, 2001 and 2000 were not significant.

The investments are generally protected from any significant currency gains or losses by the terms of the power sales agreements and other related contracts, in which payments are defined in U.S. dollars.

Restrictions on Dividend Payments and Transfer of Assets

Dividends on TECO Energy’s common stock are at the discretion of its Board of Directors. Should TECO Energy exercise its right to defer payments on its subordinated notes issued in connection with the issuance of trust preferred securities by TECO Capital Trust I or TECO Capital Trust II, TECO Energy would be prohibited from paying cash dividends on its common stock until the unpaid distributions on the subordinated notes are made. TECO Energy has not exercised that right. In addition, TECO Energy’s $380 million note indenture contains covenants which would apply only if either 1) notes are rated below BBB- by Standard & Poor’s (S&P) or below Baa3 by Moody’s or 2) notes are rated below Special Ratings Trigger (minimum of BBB- by S&P and Baa2 by Moody’s or BBB by S&P and Baa3 by Moody’s) if TECO Energy construction undertakings for the TECO/Panda projects are not substantially discharged. These covenants include limitation on restricted payments, limitations on certain liens and limitation on indebtedness.

The primary sources of funds to pay dividends on TECO Energy’s common stock are dividends from its operating companies. Tampa Electric’s first mortgage bond indenture and certain long-term debt at PGS contain restrictions that limit the payment of dividends on the common stock of Tampa Electric. Tampa Electric’s first mortgage bond indenture does not limit loans or advances. In addition, TECO Diversified, Inc., a wholly-owned subsidiary of TECO Energy and the holding company for TECO Transport, TECO Coal, TECO Coalbed Methane and TECO Solutions, has a guarantee related to a coal supply agreement that limits the payment of dividends to its common shareholder, but does not limit loans or advances. As of Dec. 31, 2002 and 2001, the balances restricted as to transfers to the parent company in the form of loans, advances or cash dividends were less than 25 percent of consolidated common equity. (See Note R.)

Lease Accounting Amendment

In April 2002, the Financial Accounting Standards Board (FASB) issued FAS 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. In addition to rescinding the aforementioned statements, FAS 145 amends FAS 13, Accounting for Leases, to eliminate an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. This statement also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. The implementation of FAS 145 has not had a significant impact on the company’s results.

Reclassifications

Certain prior year amounts were reclassified to conform with current year presentation.

B. Derivatives and Hedging

From time to time, TECO Energy enters into futures, forwards, swaps and option contracts for the following purposes:

•

To hedge the selling price for the physical production of natural gas at TECO Coalbed Methane;

•

To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations at Tampa Electric, PGS and Prior Energy;

•

To limit the exposure to interest rate fluctuations on debt issuances at TECO Energy and its other affiliates;

•

To limit the exposure to electricity, natural gas and fuel oil price fluctuations related to the operations of natural gas-fired and fuel oil-fired power plants at TPS; and

•

To limit the exposure to price fluctuations for physical purchases of fuel at TECO Transport.

TECO Energy uses derivatives only to reduce normal operating and market risks, not for speculative purposes. The company’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers. For unregulated operations, the company uses derivative instruments primarily to optimize the value of physical assets, including generation capacity, natural gas production, and natural gas delivery.

The risk management policies adopted by TECO Energy provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group which is independent of all operating companies.

Effective Jan. 1, 2001, the company adopted FAS 133, Accounting for Derivative Instruments and Hedging Activities. The new standard requires companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value, and to reflect the changes in the fair value of those instruments as either components of other comprehensive income (OCI) or in net income, depending on the designation of those instruments. The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or the loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of its reclassification. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the amount paid or received on the underlying physical transaction. Additionally, amounts defined in OCI related to an effective designated cash flow hedge must be reclassified to current earnings if the anticipated hedged transaction is no longer probable of occurring. At adoption, the company had derivatives in place at TECO Coalbed Methane that qualified for cash flow hedge accounting treatment under FAS 133, and recorded an opening swap liability of $19.0 million and an after-tax reduction to OCI of $12.6 million.

At Dec. 31, 2002, the company had derivative assets totaling $12.5 million and liabilities totaling $4.1 million. At Dec. 31, 2001, the company had derivative assets totaling $9.9 million and liabilities totaling $37.0 million. At Dec. 31, 2002 and 2001, accumulated OCI included $32.4 million and $19.2 million, respectively, of unrealized after-tax losses, representing the fair value of cash flow hedges whose transactions will occur in the future, including an unrealized loss of $37.3 million and $11.2 million for 2002 and 2001, respectively, on an equity investee’s interest rate swap and other fuel hedges designated as cash flow hedges. Amounts recorded in OCI reflect the value of derivative instruments designated as hedges, based on market prices as of the balance sheet date. These amounts are expected to fluctuate with movements in market prices and may or may not be realized as a loss upon future reclassification from OCI.

As of Dec. 31, 2002, TECO Energy had transactions in place to hedge commodity price risk and interest rate risk that qualify for cash flow hedge accounting treatment under FAS 133. During 2002, TECO Energy reclassified net pretax losses of $29.0 million to earnings for cash flow hedges, compared to pretax losses of $19.7 million in 2001. Amounts reclassified from OCI were primarily related to cash flow hedges of physical purchases of natural gas and physical sales of electricity. For these types of hedge relationships, the loss on the derivative, reclassified from OCI to earnings, is offset by the reduced expense arising from lower prices paid for spot purchases of natural gas. Conversely, reclassification of a gain from OCI to earnings is offset by the increased cost of spot purchases of natural gas.

As a result of 1) the suspension of construction on the Dell and McAdams power plants at TPS, and 2) the maintenance activity on the Frontera Power Station at TPS in early 2003, the company discontinued hedge accounting for purchases of natural gas and sales of electricity which are no longer anticipated to take place within two months of the originally designated time period for delivery. The discontinuation of hedge accounting resulted in a reclassification of a pretax gain of $0.2 million from OCI to earnings, reflecting the fair value of the related derivatives as of the discontinuation date. This gain is included in the net pretax loss reported above for 2002. Gains and losses on these derivative instruments subsequent to the discontinuation of hedge accounting treatment were recorded in earnings.

Based on the fair values at Dec. 31, 2002, pretax gains of $7.1 million are expected to be reversed from OCI to the Consolidated Statement of Income within the next twelve months. However, these gains and other future reclassifications from OCI, will fluctuate with movements in the underlying market price of the derivative instruments. Excluding interest rate risk exposures, the company does not currently have any cash flow hedges for transactions forecasted to take place in periods subsequent to 2004.

At Dec. 31, 2002 and 2001, TECO Energy had transactions in place to hedge gas storage inventory that qualify for fair value hedge accounting treatment under FAS 133. During 2002, the company recognized pretax gains of $0.7 million compared to $0.1 million in 2001. For the years ended Dec. 31, 2002 and 2001, the company also recognized pretax losses of $2.4 million and $1.5 million, respectively, relating to derivatives that do not qualify for cash flow or fair value hedge treatment that are marked to market.

C. Goodwill and Other Intangible Assets

Effective Jan. 1, 2002, TECO Energy and its subsidiaries adopted FAS 141, Business Combinations, and FAS 142, Goodwill and Other Intangible Assets. FAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting. With the adoption of FAS 142, goodwill is no longer subject to amortization. Rather, goodwill is subject to an annual assessment for impairment by applying a fair-value-based test. Under the new rules, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented, or exchanged, regardless of the acquiror’s intent to do so. These intangible assets are required to be amortized over their useful lives.

The amount of goodwill included on the consolidated balance sheets at Dec. 31, 2002 and 2001 was $193.7 million and $165.8 million, respectively, net of accumulated amortization of $9.5 million. Amortization of goodwill ceased effective Jan. 1, 2002 with the adoption of FAS 142, resulting in savings of approximately $5 million of annual amortization expense. Results for 2001 and 2000 included $4.8 million and $2.7 million of goodwill amortization expense, respectively.

The amount of intangible assets included in deferred charges and other assets on the Consolidated Balance Sheet at Dec. 31, 2002 was $11.1 million, which is net of accumulated amortization of $35.4 million, and at Dec. 31, 2001 was $28.5 million, which was net of accumulated amortization of $12.3 million. Amortizable intangible assets of $4.4 million at Dec. 31, 2002 represent customer backlog and supply agreements related to the Prior Energy acquisition in November 2001. The company is amortizing these intangibles over the current year period. Amortization expense of $23.1 million and $12.3 million, respectively, was recorded in 2002 and 2001. There were no intangible assets at Dec. 31, 2000. Unamortizable intangible assets of $6.7 million at Dec. 31, 2002 represent licenses held by TPS related to gasification technologies.

TECO Energy continues to review recorded goodwill and intangibles as required under FAS 142, and has not identified any impairments. The reconciliation of reported net income and earnings per share to adjusted net income excluding goodwill amortization expense for 2002, 2001 and 2000 follows:

Pro Forma Effect of FAS 142 Adoption

(millions, except per share amounts)	2002		2001		2000
Net income:
As reported	$	330.1	$	303.7	$	250.9
Add: Goodwill amortized, net of tax		—		3.7		2.4

Adjusted net income	$	330.1	$	307.4	$	253.3

Earnings per share – basic:
As reported	$	2.15	$	2.26	$	1.99
Add: Goodwill amortized, net of tax		—		.03		.02

Adjusted basic earnings per share	$	2.15	$	2.29	$	2.01

Earnings per share – diluted:
As reported	$	2.15	$	2.24	$	1.97
Add: Goodwill amortized, net of tax		—		.03		.02

Adjusted diluted earnings per share	$	2.15	$	2.27	$	1.99

D. Regulatory Assets and Liabilities

Tampa Electric and PGS maintain their accounts in accordance with recognized policies of the FPSC. In addition, Tampa Electric maintains its accounts in accordance with recognized policies prescribed or permitted by the FERC. These policies conform with generally accepted accounting principles in all material respects.

Tampa Electric and PGS apply the accounting treatment permitted by FAS 71, Accounting for the Effects of Certain Types of Regulation. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel; purchased power, conservation and environmental costs; and deferral of costs as regulatory assets when cost recovery is ordered over a period longer than a fiscal year, to the period that the regulatory agency recognizes them. Details of the regulatory assets and liabilities as of Dec. 31, 2002 and 2001 are presented in the following table:

Regulatory Assets and Liabilities

(millions) Dec. 31,	2002		2001
Regulatory assets:
Regulatory tax asset (1)	$	54.9	$	41.3
Other:
Cost recovery clauses		34.7		105.2
Coal contract buy-out (2)		5.4		8.1
Unamortized refinancing costs (3)		35.9		13.7
Environmental remediation		20.3		22.3
Competitive rate adjustment		7.4		5.9
Other		4.6		1.8

		108.3		157.0

Total regulatory assets	$	163.2	$	198.3

Regulatory liabilities:
Regulatory tax liability (1)	$	36.6	$	43.1
Other:
Deferred allowance auction credits		2.1		1.1
Cost recovery clauses		2.2		0.5
Revenue refund		—		6.3
Environmental remediation		20.3		22.3
Transmission and distribution storm reserve		36.0		32.0
Deferred gain on property sales (4)		0.9		0.9

		61.5		63.1

Total regulatory liabilities	$	98.1	$	106.2

(1)

Related primarily to plant life. Includes excess deferred taxes of $20.9 million and $24.6 million as of Dec. 31, 2002 and 2001, respectively.

(2)

Amortized over a 10-year period ending December 2004.

(3)

Unamortized refinancing costs:

Related to debt transactions as follows (millions):		Amortized until:
$155.0		2003
$ 51.6		2005
$ 22.1		2007
$ 25.0		2011
$ 50.0		2011
$150.0		2012
$150.0		2012
$ 85.9		2014
$ 25.0		2021
$100.0		2022

(4)

Amortized over a 5-year period with various ending dates.

E. Long-Term Debt (millions) Dec. 31,	Due	2002		2001
TECO Energy
Notes: 5.31% for 2001 (1)	2002	$	—	$	200.0
Notes: 7.2% (effective rate of 7.38%) (2)	2011		600.0		600.0
Floating rate notes: 5.2% for 2001 (1)	2002		—		400.0
Notes: 6.125% (effective rate of 6.31%) (2)	2007		300.0		—
Notes: 7% (effective rate of 7.08%) (2)	2012		400.0		—
Notes: 10.5% (effective rate of 12.29%) (2)	2007		380.0		—

			1,680.0		1,200.0

E. Long-Term Debt-continued (millions) Dec. 31,	Due	2002			2001
Tampa Electric
First mortgage bonds (issuable in series):
7.75% (effective rate of 7.96%)	2022		75.0			75.0
6.125% (effective rate of 6.61%)	2003		75.0			75.0
Installment contracts payable (3):
5.75%	2002		—			22.5
7.875% Refunding bonds (4)	2002		—			25.0
8% Refunding bonds (4)	2002		—			100.0
6.25% Refunding bonds (effective rate of 6.81%) (5)	2034		86.0			86.0
5.85% (effective rate of 5.88%)	2030		75.0			75.0
5.1% Refunding bonds (effective rate of 5.78%) (6)	2013		60.7			—
5.5% Refunding bonds (effective rate of 6.35%) (6)	2023		86.4			—
4% for 2002 (effective rate of 4.21%) and variable rate of 1.45% for 2001 (1) (7)	2025		51.6			51.6
4% for 2002 (effective rate of 4.16%) and variable rate of 1.47% for 2001 (1) (7)	2018		54.2			54.2
4.25% for 2002 (effective rate of 4.43%) and variable rate of 1.52% for 2001 (1) (7)	2020		20.0			20.0
Notes: 5.86% (1)	2002		—			100.0
Notes: 6.875% (effective rate of 6.98%) (2)	2012		210.0			210.0
Notes: 6.375% (effective rate of 7.34%) (2)	2012		330.0			—
Notes: 5.375% (effective rate of 5.58%) (2)	2007		125.0			—

			1,248.9			894.3

Peoples Gas System
Senior Notes (8)
10.35%	2007		4.2			5.0
10.33%	2008		5.6			6.4
10.3%	2009		7.2			7.8
9.93%	2010		7.4			8.0
8%	2012		25.4			27.5
Notes: 5.86% (1)	2002		—			50.0
Notes: 6.875% (effective rate of 6.98%) (2)	2012		40.0			40.0
Notes: 6.375% (effective rate of 7.34%) (2)	2012		70.0			—
Notes: 5.375% (effective rate of 5.58%) (2)	2007		25.0			—

			184.8			144.7

Diversified companies
Dock and wharf bonds, 5% (3)	2007		110.6			110.6
Non-recourse secured facility notes, Series A: 7.8%	2003-2012		111.0			118.5
Non-recourse secured facility notes: 9.875%	2002		—			17.1
Non-recourse secured facility notes, variable rate:
4.63% for 2002 and 5.43% for 2001 (1)	2003-2007		50.1			57.9
Non-recourse secured facility notes: 10.1%	2003-2009		16.4			16.9
Non-recourse secured facility notes: 9.629%	2003-2010		24.8			28.0
Non-recourse secured facility note, variable rate: 6.88% for 2002 (1)	2004-2009		16.0			—
Non-recourse secured facility note, variable rate: 5% for 2002 (1)	2004-2009		14.0			—
Capital lease: implicit rate of 8.5%	2003		25.3			27.6

			368.2			376.6

TECO Finance
Medium-term notes payable: 7.54% for 2001 (1)	2002		—			9.0

Unamortized debt premium (discount), net			(30.5	)		6.7

			3,451.4			2,631.3
Less amount due within one year (9)			127.1			788.8

Total long-term debt		$	3,324.3		$	1,842.5

(1)

Composite year-end interest rate.

(2)

These notes are subject to redemption in whole or in part, at any time, at the option of the company.

(3)

Tax-exempt securities.

(4)

Proceeds of these bonds were used to refund bonds with interest rates of 11.625%–12.625%. For accounting purposes, interest expense has been recorded using blended rates of 8.28%–8.66% on the original and refunding bonds, consistent with regulatory treatment.

(5)

Proceeds of these bonds were used to refund bonds with an interest rate of 9.9% in February 1995. For accounting purposes, interest expense has been recorded using a blended rate of 6.52% on the original and refunding bonds, consistent with regulatory treatment.

(6)

Proceeds of these bonds were used to refund bonds with interest rates of 5.75%–8%.

(7)

The interest rate on these bonds was fixed for a five-year term on Aug. 5, 2002.

(8)

These long-term debt agreements contain various restrictive covenants, including provisions related to interest coverage, maximum levels of debt to total capitalization and limitations on dividends.

(9)

Of the amount due in 2003, $0.8 million may be satisfied by the substitution of property in lieu of cash payments.

TECO Transport entered into a capital lease agreement with Midwest Marine Management Company in March 1998 for the charter of additional capacity. This lease covers 110 river barges and three towboats, classified as property, plant and equipment on the balance sheet; the corresponding $35 million five-year lease commitment was recorded as long-term debt on the balance sheet. The future minimum lease payments under the capitalized lease as of Dec. 31, 2002 are $25.8 million. This represents $25.3 million present value of net minimum lease payments and $0.5 million of interest, all due in 2003.

Substantially all of the property, plant and equipment of Tampa Electric is pledged as collateral to secure its first mortgage bonds and certain pollution control equipment is pledged to secure certain installment contracts payable. TECO Energy’s maturities and annual sinking fund requirements of long-term debt for the years 2004, 2005, 2006 and 2007 are $31.9 million, $35.7 million, $38.0 million and $975.2 million, respectively. Of these amounts $0.8 million per year for 2004 through 2007 may be satisfied by the substitution of property in lieu of cash payments.

At Dec. 31, 2002, total long-term debt had a carrying amount of $3,324.3 million and an estimated fair market value of $3,288.7 million. The estimated fair market value of long-term debt was based on quoted market prices for the same or similar issues, on the current rates offered for debt of the same remaining maturities, or for long-term debt issues with variable rates that approximate market rates, at carrying amounts. The carrying amount of long-term debt due within one year approximated fair market value because of the short maturity of these instruments.

F. Short-Term Debt

At Dec. 31, 2002 and 2001, notes payable consisted of the following:

Notes Payable

(millions) Dec. 31,	2002		2001
Credit facilities outstanding	$	350.0	$	—
Commercial paper		10.5		638.9

Total notes payable	$	360.5	$	638.9

The weighted average interest rate on outstanding notes payable at Dec. 31, 2002 and 2001 was 1.88% and 1.99%, respectively.

At Dec. 31, 2002 and 2001, the following credit facilities and related borrowings existed:

Credit Facilities

	Dec. 31, 2002						Dec. 31, 2001
(millions)	Credit Facilities		Borrowings Outstanding		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding		Letters of Credit Outstanding
Tampa Electric
1-year facility	$	300.0	$	—	$	—	$	300.0	$	—	$	—
TECO Energy
1-year facility		350.0		350.0		—		350.0		—		—
TECO Energy
3-year facility		350.0		—		179.8		350.0		—		—

Totals	$	1,000.0	$	350.0	$	179.8	$	1,000.0	$	—	$	—

Tampa Electric’s credit facility has a maturity date of November 2003. TECO Energy’s one-year facility also matures in November 2003 and its 3-year facility matures in November 2004. These credit facilities require facility fees ranging from 15 to 20 basis points. Within its 3-year facility, TECO Energy has $250 million of capacity to issue letters of credit. These letters of credit require issuance fees of 12.5 basis points and lenders fees of 55 basis points.

In order to utilize the credit facilities, TECO Energy’s debt-to-capital ratio, as defined in the credit agreement, may not exceed 65.0% at the end of the applicable quarter. At Dec. 31, 2002, TECO Energy’s debt-to-capital ratio was 55.9%. Under Tampa Electric’s credit facility, Tampa Electric’s debt-to-capital ratio may not exceed 60.0% measured at the end of the applicable quarter and its earnings before interest, taxes, depreciation and amortization (EBITDA) to interest coverage ratio must be at least 2.5 times. At Dec. 31, 2002, Tampa Electric’s debt-to-capital ratio was 43.9% and its EBITDA to interest coverage ratio was 7.8 times. (See Note R.)

G. Preferred Securities

In November 2000, TECO Energy established TECO Capital Trust I (the Trust) for the sole purpose of issuing Trust Preferred Securities (TRuPS) and using the proceeds to purchase company preferred securities from TECO Funding Company I, LLC (TECO Funding). On Dec. 20, 2000, the Trust issued 8 million shares of $25 par, 8.5% TRuPS, due 2041, with an aggregate liquidation value of $200 million. Currently, all 8 million shares of the TRuPS are outstanding. Each TRuPS represents an undivided beneficial interest in the assets of the Trust. The Trust used the proceeds from the sale of the TRuPS to purchase a corresponding amount of company preferred securities of TECO Funding. TECO Funding used the proceeds from the sale of the company preferred securities to the Trust of $200 million and the sale of $6.2 million of its common securities to TECO Energy, to purchase $206.2 million of 8.5% junior subordinated notes of TECO Energy, due 2041. The junior subordinated notes are the sole assets of TECO Funding and the company preferred securities are the sole assets of the Trust. TECO Energy’s proceeds from the sale of the junior subordinated notes were used to reduce the commercial paper balances of TECO Finance and for general corporate purposes. TECO Energy has guaranteed the payments to the holders of the company preferred securities and indirectly, the payments to the holders of the TRuPS, as a result of their beneficial interest in the company preferred securities. Distributions are payable quarterly in arrears on January 31, April 30, July 31, and October 31 of each year. Distributions were $17.0 million and $14.6 million in 2002 and 2001, respectively. No distributions were made in 2000.

The junior subordinated notes may be redeemed at the option of TECO Energy at any time on or after Dec. 20, 2005 at 100% of their principal amount plus accrued interest through the redemption date. If TECO Energy redeems the junior subordinated notes in full before their maturity date, then TECO Funding is required to redeem the company preferred securities and common securities, in accordance with their terms. If TECO Energy redeems the junior subordinated notes in part but not in full before their maturity date, then TECO Funding will redeem the company preferred securities in full prior to any payment being made on the common securities. Upon any liquidation of the company preferred securities, holders of the TRuPS would be entitled to the liquidation preference of $25 per share plus all accrued and unpaid dividends through the date of redemption.

In January 2002, TECO Energy sold 17.965 million mandatorily convertible equity security units in the form of 9.5% equity units at $25 per unit resulting in $436 million of net proceeds. Each equity unit consisted of $25 in principal amount of a trust preferred security of TECO Capital Trust II, a Delaware business trust formed for the purpose of issuing these securities, with a stated liquidation amount of $25 and a contract to purchase shares of common stock of TECO Energy in January 2005 at a price per share of between $26.29 and $30.10 based on the market price at that time. The equity units represent an indirect interest in a corresponding amount of TECO Energy 5.11% subordinated debt. The holders of these contracts are entitled to quarterly contract adjustment payments at the annualized rate of 4.39% of the stated amount of $25 per year through and including Jan. 15, 2005. The net proceeds from the offering were used to repay short-term debt and for general corporate purposes.

H. Preferred Stock

Preferred stock of TECO Energy – $1 par 10 million shares authorized, none outstanding.

Preference stock of Tampa Electric – no par 2.5 million shares authorized, none outstanding.

Preferred stock of Tampa Electric – no par 2.5 million shares authorized, none outstanding.

Preferred stock of Tampa Electric – $100 par value 1.5 million shares authorized, none outstanding.

I. Common Stock

Stock-Based Compensation

In April 1996, the shareholders approved the 1996 Equity Incentive Plan (the “1996 Plan”). The 1996 Plan superseded the 1990 Equity Incentive Plan (the “1990 Plan”), and no additional grants will be made under the 1990 Plan. The rights of the holders of outstanding options under the 1990 Plan were not affected. The purpose of the 1996 Plan is to attract and retain key employees of the company, to provide an incentive for them to achieve long-range performance goals and to enable them to participate in the long-term growth of the company. The 1996 Plan amended the 1990 Plan to increase the number of shares of common stock subject to grants by 3,750,000 shares, expand the types of awards available to be granted and specify a limit on the maximum number of shares with respect to which stock options and stock appreciation rights may be made to any participant under the plan. Under the 1996 Plan, the Compensation Committee of the Board of Directors may award stock grants, stock options and/or stock equivalents to officers and key employees of TECO Energy and its subsidiaries.

The Compensation Committee has discretion to determine the terms and conditions of each award, which may be subject to conditions relating to continued employment, restrictions on transfer or performance criteria.

In 2002, under the 1996 Plan, 1,769,880 stock options were granted, with a weighted average option price of $27.97 and a maximum term of 10 years. In addition, 255,242 shares of restricted stock were awarded, each with a weighted average fair value of $27.97. Compensation expense recognized for stock grants awarded under the 1996 Plan was $1.7 million, $2.8 million and $4.6 million in 2002, 2001 and 2000, respectively. Half the stock grants awarded in 2002 and all of the stock grants awarded in 2001 and 2000 are performance shares, restricted subject to meeting specified total shareholder return goals, vesting in three years with final payout ranging from zero to 200% of the original grant. Adjustments are made to reflect contingent shares which could be issuable based on current period results. The consolidated balance sheets at Dec. 31, 2002 and 2001 reflected a ($6.3) million and a $1.1 million liability respectively, classified as other deferred credits, for these contingent shares. The remaining stock grants are restricted subject generally to continued employment, with the 2002 stock grants vesting in three years, the 1998 stock grants vesting in five years, and the 1997 and 1996 stock grants vesting at normal retirement age.

In April 2001, the shareholders approved an amendment to the 1996 Plan to increase the number of shares of common stock subject to grants by 6.3 million.

Stock option transactions during the last three years under the 1996 Plan and the 1990 Plan (collectively referred to as the “Equity Plans”) are summarized as follows:

Stock Options—Equity Plans

	Option Shares (thousands)		Weighted Avg. Option Price
Balance at Dec. 31, 1999	3,827		$	22.64
Granted	1,264		$	21.33
Exercised	(488	)	$	20.15
Cancelled	(44	)	$	23.61

Balance at Dec. 31, 2000	4,559		$	22.54
Granted	1,268		$	31.39
Exercised	(605	)	$	21.53
Cancelled	(32	)	$	26.88

Balance at Dec. 31, 2001	5,190		$	24.79
Granted	1,770		$	27.97
Exercised	(487	)	$	20.93
Cancelled	(57	)	$	27.03

Balance at Dec. 31, 2002	6,416		$	25.94

Exercisable at Dec. 31, 2002	0			—
Available for future grant at Dec. 31, 2002	4,288

As of Dec. 31, 2002, the 6.4 million options outstanding under the Equity Plans are summarized below.

Stock Options Outstanding at Dec. 31, 2002

Option Shares (thousands)	Range of Option Prices	Weighted Avg. Option Price	Weighted Avg. Remaining Contractual Life
2,099	$19.44-$22.48	$21.16	6 Years
705	$23.55-$25.97	$24.07	4 Years
3,612	$27.56-$31.58	$29.08	8 Years

In April 1997, the Shareholders approved the 1997 Director Equity Plan (the “1997 Plan”), as an amendment and restatement of the 1991 Director Stock Option Plan (the “1991 Plan”). The 1997 Plan supersedes the 1991 Plan, and no additional grants will be made under the 1991 Plan. The rights of the holders of outstanding options under the 1991 Plan will not be affected. The purpose of the 1997 Plan is to attract and retain highly qualified non-employee directors of the company and to encourage them to own shares of TECO Energy common stock. The 1997 Plan is administered by the Board of Directors. The 1997 Plan amended the 1991 Plan to increase the number of shares of common stock subject to grants by 250,000 shares, expanded the types of awards available to be granted and replaced the current fixed formula grant by giving the Board discretionary authority to determine the amount and timing of awards under the Plan.

In 2002, 27,500 options were granted, with a weighted average option price of $27.97. Transactions during the last three years under the 1997 Plan are summarized as follows:

Stock Options—Director Equity Plans

	Option Shares (thousands)		Weighted Avg. Option Price
Balance at Dec. 31, 1999	273		$	21.25
Granted	30		$	23.49
Exercised	(33	)	$	18.57
Cancelled	(12	)	$	25.15

Balance at Dec. 31, 2000	258		$	21.68
Granted	35		$	31.26
Exercised	(91	)	$	19.12
Cancelled	—			—

Balance at Dec. 31, 2001	202		$	24.49
Granted	28		$	27.97
Exercised	(22	)	$	20.95
Cancelled	(2	)	$	27.56

Balance at Dec. 31, 2002	206		$	25.31

Exercisable at Dec. 31, 2002	0			—
Available for future grant at Dec. 31, 2002	270

As of Dec. 31, 2002, the 206,000 options outstanding under the 1997 Plan with option prices of $19.81-$31.575, had a weighted average option price of $25.31 and a weighted average remaining contractual life of six years.

TECO Energy has adopted the disclosure-only provisions of FAS 123, Accounting for Stock-Based Compensation, but applies Accounting Principles Board Opinion No. 25 and related interpretations in accounting for its plans. Therefore, since stock options are granted with an option price greater than or equal to the fair value on date of grant, no compensation expense has been recognized for stock options granted under the 1996 Plan and the 1997 Plan. If the company had elected to recognize compensation expense for stock options based on the fair value at grant date, consistent with the method prescribed by FAS 123, net income and earnings per share would have been reduced to the pro forma amounts as follows. These pro forma amounts were determined using the Black-Scholes valuation model with weighted average assumptions as follows.

Pro Forma Disclosure — Stock Options

	2002			2001			2000
Net income from continuing operations (millions)
As reported	$	298.2		$	273.8		$	227.5
Pro forma expense (1)		5.1			4.3			2.6

Pro forma	$	293.1		$	269.5		$	224.9

Net income (millions)
As reported	$	330.1		$	303.7		$	250.9
Pro forma expense (1)		5.1			4.3			2.6

Pro forma	$	325.0		$	299.4		$	248.3

Net income from continuing operations—EPS basic
As reported	$	1.95		$	2.04		$	1.81
Pro forma	$	1.91		$	2.00		$	1.79

Net income—EPS basic
As reported	$	2.15		$	2.26		$	1.99
Pro forma	$	2.12		$	2.23		$	1.97

Assumptions
Risk-free interest rate		5.09	%		4.86	%		6.24	%
Expected lives (in years)		6			6			6
Expected stock volatility		25.92	%		27.45	%		22.93	%
Dividend yield		5.47	%		5.46	%		5.15	%

(1)

Compensation expense for stock options determined under fair-value based method, after-tax.

Dividend Reinvestment Plan

In 1992, TECO Energy implemented a Dividend Reinvestment and Common Stock Purchase Plan (DRP). TECO Energy raised $11.2 million, $8.6 million and $8.1 million of common equity from this plan in 2002, 2001 and 2000, respectively.

Common Stock and Treasury Stock

In September 1999, TECO Energy began a program to repurchase up to $150 million of its outstanding common stock. Shares acquired constituted treasury shares. In 1999 and 2000, the company acquired 7.0 million shares of its outstanding common stock at a cost of $144.7 million, or an average per share price of $20.55. The company’s share repurchase program favorably impacted earnings in 2000 by approximately $0.06 per share.

On Mar. 12, 2001, the company completed a public offering of 8.625 million common shares at $27.75 per share, 7.0 million shares of which were reissued from treasury shares.

On Oct. 4, 2001, S&P announced the inclusion of TECO Energy shares in the S&P 500 Index effective as of the market close on Oct. 9, 2001. On Oct. 12, 2001, TECO Energy issued 3.5 million additional common shares at $26.72 per share. The sales of the common shares resulted in total net proceeds to TECO Energy of $325.5 million in 2001, which were used to fund capital expenditures, for working capital requirements, general corporate purposes and to repay short-term debt.

In June 2002, the company completed a public offering of 15.525 million common shares at a price to the public of $23.00 per share. The sale of these shares resulted in net proceeds to the company of approximately $346.4 million, which were used to repay short-term debt and for general corporate purposes. In October 2002, the company issued 19.385 million common shares at a price to the public of $11.00 per share. The sale of these shares resulted in net proceeds to the company of approximately $206.8 million, which were used to repay short-term debt.

Shareholder Rights Plan

In accordance with the company’s Shareholder Rights Plan, a Right to purchase one additional share of the company’s common stock at a price of $90 per share is attached to each outstanding share of the company’s common stock. The Rights expire in May 2009, subject to extension. The Rights will become exercisable 10 business days after a person acquires 10 percent or more of the company’s outstanding common stock or commences a tender offer that would result in such person owning 10 percent or more of such stock. If any person acquires 10 percent or more of the outstanding common stock, the rights of holders, other than the acquiring person, become rights to buy shares of common stock of the company (or of the acquiring company if the company is involved in a merger or other business combination and is not the surviving corporation) having a market value of twice the exercise price of each Right.

The company may redeem the Rights at a nominal price per Right until 10 business days after a person acquires 10 percent or more of the outstanding common stock.

Employee Stock Ownership Plan

Effective Jan. 1, 1990, TECO Energy amended the TECO Energy Group Retirement Savings Plan, a tax-qualified benefit plan available to substantially all employees, to include an employee stock ownership plan (ESOP). During 1990, the ESOP purchased 7 million shares of TECO Energy common stock on the open market for $100 million. The share purchase was financed through a loan from TECO Energy to the ESOP. This loan is at a fixed interest rate of 9.3% and will be repaid from dividends on ESOP shares and from TECO Energy’s contributions to the ESOP.

TECO Energy’s contributions to the ESOP were $13.6 million, $5.6 million and $6.8 million in 2002, 2001 and 2000, respectively. TECO Energy’s annual contribution equals the interest accrued on the loan during the year plus additional principal payments needed to meet the matching allocation requirements under the plan, less dividends received on the ESOP shares. The components of net ESOP expense recognized for the past three years are as follows:

ESOP Expense

(millions)	2002			2001			2000
Interest expense	$	4.3		$	5.2		$	6.0
Compensation expense		12.2			7.4			6.9
Dividends		(8.5	)		(8.5	)		(8.5	)

Net ESOP expense	$	8.0		$	4.1		$	4.4

Compensation expense was determined by the shares allocated method.

At Dec. 31, 2002, the ESOP had 4.0 million allocated shares, 0.3 million committed-to-be-released shares, and 1.7 million unallocated shares. Shares are released to provide employees with the company match in accordance with the terms of the TECO Energy Group Retirement Savings Plan and in lieu of dividends on allocated ESOP shares. The dividends received by the ESOP are used to pay debt service on the loan between TECO Energy and the ESOP.

For financial statement purposes, the unallocated shares of TECO Energy stock are reflected as a reduction of common equity, classified as unearned compensation. Dividends on all ESOP shares are recorded as a reduction of retained earnings, as are dividends on all TECO Energy common stock. The tax benefit related to the dividends paid to the ESOP for allocated shares is a reduction of income tax expense and for unallocated shares is an increase in retained earnings. All ESOP shares are considered outstanding for earnings per share computations.

J. Comprehensive Income

FAS 130, Reporting Comprehensive Income, requires that comprehensive income, which includes net income as well as certain changes in assets and liabilities recorded in common equity, be reported in the financial statements. TECO Energy reported the following comprehensive income (loss) in 2002, 2001 and 2000 related to changes in the fair value of cash flow hedges, foreign currency adjustments and adjustments to the minimum pension liability associated with the company’s supplemental executive retirement plan:

Comprehensive Income (loss)

(millions)	Gross			Tax			Net
2002
Unrealized (loss) gain on cash flow hedges	$	(8.7	)	$	(4.0	)	$	(4.7	)
Less: Loss (gain) reclassified to net income		29.0			11.4			17.6

Gain (loss) on cash flow hedges		20.3			7.4			12.9
Portion of equity investee’s loss on cash flow hedges		(42.5	)		(16.4	)		(26.1	)
Foreign currency adjustments		(1.2	)		—			(1.2	)
Pension adjustments		(7.2	)		(2.8	)		(4.4	)

Total other comprehensive income (loss)	$	(30.6	)	$	(11.8	)	$	(18.8	)

2001
Initial adoption of FAS 133	$	(19.0	)	$	(7.3	)	$	(11.7	)
Unrealized (loss) gain on cash flow hedges		(13.9	)		(5.5	)		(8.4	)
Less: Loss (gain) reclassified to net income		19.7			7.6			12.1

Gain (loss) on cash flow hedges		(13.2	)		(5.2	)		(8.0	)
Portion of equity investee’s loss on cash flow hedges		(18.2	)		(7.0	)		(11.2	)
Pension adjustments		0.5			0.2			0.3

Total other comprehensive income (loss)	$	(30.9	)	$	(12.0	)	$	(18.9	)

2000
Pension adjustments	$	3.3		$	1.3		$	2.0

Total other comprehensive income (loss)	$	3.3		$	1.3		$	2.0

K. Employee Postretirement Benefits

Pension Benefits

TECO Energy has a non-contributory defined benefit retirement plan which covers substantially all employees. Benefits are based on employees’ age, years of service and final average earnings. On April 1, 2000, the plan was amended to provide for benefits to be earned and payable substantially on a lump sum basis through an age and service credit schedule for eligible participants leaving the company on or after July 1, 2001. Other significant provisions of the plan, such as eligibility, definitions of credited service, final average earnings, etc., were largely unchanged. This amendment resulted in decreased pension expense of approximately $0.8 million and $2.0 million in 2001 and 2000, respectively, and a reduction of benefit obligation of $6.2 million and $14.4 million at Sept. 30, 2001 and Dec. 31, 2000, respectively.

The company’s policy is to fund the plan within the guidelines set by ERISA for the minimum annual contribution and the maximum allowable as a tax deduction by the IRS. About 53 percent of plan assets were invested in common stock and 47 percent in fixed income investments at Sept. 30, 2002.

Amounts shown also include the unfunded obligations for the supplemental executive retirement plans, non-qualified, non-contributory defined benefit retirement plans available to certain senior management. TECO Energy reported other comprehensive loss of $4.4 million in 2002 and other comprehensive income of $0.3 million and $2.0 million in 2001 and 2000, respectively, related to adjustments to the minimum pension liability associated with the supplemental executive retirement plans.

In 2001, TECO Energy elected to change the measurement date for pension obligations and plan assets from Dec. 31 to Sept. 30. The effect of this accounting change was not material.

Other Postretirement Benefits

TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 meeting certain service requirements. The company contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and June 30, 2001, is limited to a defined dollar benefit based on years of service. On April 1, 2000, the company adopted changes to this program for participants retiring from the company on or after July 1, 2001. The company contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after July 1, 2001, is limited to a defined dollar benefit based on an age and service schedule. The impact of this amendment, including a change in the company’s commitment for future retirees combined with a grandfathering provision for current retired participants, resulted in a reduction in the benefit obligation of $1.4 million in 2001. Postretirement benefit levels are substantially unrelated to salary. The company reserves the right to terminate or modify the plans in whole or in part at any time.

In 2001, TECO Energy elected to change the measurement date for benefit obligations from Dec. 31 to Sept. 30. The effect of this accounting change was not material.

The following charts summarize the income statement and balance sheet impact, as well as the benefit obligations, assets, funded status and rate assumptions associated with the pension and other postretirement benefits.

Benefit Expense

	Pension Benefits									Other Postretirement Benefits
(millions)	2002			2001			2000			2002		2001		2000
Components of net periodic benefit expense
Service cost (benefits earned during the period)	$	11.8		$	11.2		$	10.7		$	3.5	$	3.4	$	3.0
Interest cost on projected benefit obligations		28.7			27.9			27.5			11.2		10.9		8.9
Expected return on assets		(42.9	)		(42.0	)		(40.8	)		—		—		—
Amortization of:
Transition obligation (asset)		(1.1	)		(1.1	)		(1.0	)		2.7		2.7		2.7
Prior service cost (benefit)		(0.5	)		(0.5	)		0.2			1.9		2.0		1.7
Actuarial (gain) loss		(3.7	)		(4.4	)		(5.6	)		0.1		0.4		(0.2	)

Pension expense (benefit)		(7.7	)		(8.9	)		(9.0	)		19.4		19.4		16.1
Special termination benefit charge		2.7			—			1.1			0.6		—		0.2
Additional amounts recognized		—			—			—			—		—		0.9

Net pension expense (benefit) recognized in the Consolidated Statements of Income	$	(5.0	)	$	(8.9	)	$	(7.9	)	$	20.0	$	19.4	$	17.2

The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for non-qualified pension plans with accumulated benefit obligations in excess of plan assets were $41.3 million, $32.8 million and $0, respectively, as of Sept. 30, 2002 and $27.3 million, $23.5 million and $0, respectively, as of Sept. 30, 2001.

Employee Postretirement Benefits

	Pension Benefits						Other Postretirement Benefits
(millions)	2002			2001			2002			2001
Change in benefit obligation
Net benefit obligation at prior measurement date	$	382.3		$	379.9		$	150.2		$	130.8
Service cost		11.8			11.2			3.5			3.4
Interest cost		28.7			27.9			11.2			10.9
Plan participants’ contributions		—			—			1.0			0.9
Actuarial (gain) loss		58.3			(8.7	)		25.6			11.6
Plan amendments		1.1			(6.2	)		—			(1.4	)
Special termination benefits		2.7			—			0.6			—
Gross benefits paid		(29.8	)		(21.8	)		(7.5	)		(6.0	)

Net benefit obligation at measurement date	$	455.1		$	382.3		$	184.6		$	150.2

Change in plan assets
Fair value of plan assets at prior measurement date	$	428.0		$	493.8		$	—		$	—
Actual return on plan assets		(24.9	)		(43.7	)		—			—
Employer contributions		1.7			2.1			6.5			5.1
Plan participants’ contributions		—			—			1.0			0.9
Gross benefits paid (including expenses)		(32.9	)		(24.2	)		(7.5	)		(6.0	)

Fair value of plan assets at measurement date	$	371.9		$	428.0		$	—		$	—

Funded status
Funded status at measurement date	$	(83.2	)	$	45.7		$	(184.6	)	$	(150.2	)
Net contributions after measurement date		0.4			0.4			1.9			1.7
Unrecognized net actuarial (gain) loss		88.9			(44.0	)		42.4			16.9
Unrecognized prior service cost (benefit)		(7.4	)		(9.0	)		22.4			24.3
Unrecognized net transition obligation (asset)		(2.5	)		(3.6	)		27.4			30.1

Accrued liability at end of year	$	(3.8	)	$	(10.5	)	$	(90.5	)	$	(77.2	)

Amounts recognized in the statement of financial position
Prepaid benefit cost	$	14.7		$	6.3		$	—		$	—
Accrued benefit cost		(18.5	)		(16.8	)		(90.5	)		(77.2	)
Additional minimum liability		(13.8	)		(6.2	)		—			—
Intangible asset		1.5			1.1			—			—
Accumulated other comprehensive income		12.3			5.1			—			—

Net amount recognized at end of year	$	(3.8	)	$	(10.5	)	$	(90.5	)	$	(77.2	)

Assumptions used in determining actuarial valuations
Discount rate to determine projected benefit obligation		6.75	%		7.5	%		6.75	%		7.5	%
Rate of increase in compensation levels		4.8	%		4.7	%
Plan asset growth rate through time		9.0	%		9.0	%

The assumed health care cost trend rate for medical costs was 12.5% in 2002 and decreases to 5.0% in 2013 and thereafter.

A 100 basis point increase in the medical trend rates would produce a 7 percent ($1.1 million) increase in the aggregate service and interest cost for 2002 and a 5 percent ($9.5 million) increase in the accumulated postretirement benefit obligation as of Sept. 30, 2002.

A 100 basis point decrease in the medical trend rates would produce a 3 percent ($0.5 million) decrease in the aggregate service and interest cost for 2002 and a 3 percent ($5.0 million) decrease in the accumulated postretirement benefit obligation as of Sept. 30, 2002.

L. Other Non-Operating Items Affecting Net Income

2002

In 2002, TECO Energy recorded $8.8 million of after-tax charges ($14.1 million pretax) to adjust asset valuations. The adjustments included a $5.8 million after-tax charge ($9.2 million pretax) related to the proposed sale of TPS’ investment in the ECKG project, and a $3.0 million after-tax charge ($4.9 million pretax) at TECO Investments related to an aircraft leased to US Airways, which has filed for bankruptcy.

In November 2002, the proceeds from the issuance of TECO Energy notes were used, in part, to pay the $34.1 million option premium associated with the refinancing of $200 million of notes. The $34.1 million option premium ($20.9 million after-tax) was recognized as a charge in 2002.

2001

In the first quarter of 2001, TECO Energy recorded $7.2 million of after-tax charges ($11.1 million pretax) to adjust asset valuations. The adjustments included a $6.1 million after-tax charge ($9.3 million pretax) related to the sale of TPS’ minority interests in Energía Global International, Ltd. (EGI) which owned smaller power generation projects in Central America, and a $1.1 million after-tax charge ($1.8 million pretax) to adjust the carrying value of leveraged leases at TECO Investments.

2000

In 2000, TECO Energy’s results included an $8.3 million after-tax gain from the US Propane and Heritage Propane transactions offset by after-tax charges of $5.2 million to adjust the value of leveraged leases and $3.8 million to adjust property values at TECO Properties. Because of the offsetting nature of these items, there was no significant effect on earnings in 2000.

M. Income Tax Expense

Income tax expense consists of the following components:

Income Tax Expense

(millions)	Federal			State			Total
2002
Currently payable	$	41.1		$	14.0		$	55.1
Deferred		(81.7	)		(7.0	)		(88.7	)
Amortization of investment tax credits		(4.8	)		—			(4.8	)

Income tax benefit from continuing operations		(45.4	)		7.0			(38.4	)

Currently payable		—			2.0			2.0
Deferred		(7.4	)		(0.4	)		(7.8	)

Income tax benefit from discontinued operations		(7.4	)		1.6			(5.8	)

Total income tax expense (benefit)	$	(52.8	)	$	8.6		$	(44.2	)

2001
Currently payable	$	85.7		$	18.3		$	104.0
Deferred		(94.1	)		(7.1	)		(101.2	)
Amortization of investment tax credits		(4.9	)		—			(4.9	)

Income tax benefit from continuing operations		(13.3	)		11.2			(2.1	)

Currently payable		(7.9	)		1.6			(6.3	)
Deferred		(1.4	)		(0.3	)		(1.7	)

Income tax benefit from discontinued operations		(9.3	)		1.3			(8.0	)

Total income tax expense (benefit)	$	(22.6	)	$	12.5		$	(10.1	)

2000
Currently payable	$	103.3		$	8.4		$	111.7
Deferred		(79.5	)		2.0			(77.5	)
Amortization of investment tax credits		(4.9	)		—			(4.9	)

Income tax expense from continuing operations		18.9			10.4			29.3

Currently payable		(10.7	)		—			(10.7	)
Deferred		(1.6	)		1.5			(0.1	)

Income tax benefit from discontinued operations		(12.3	)		1.5			(10.8	)

Total income tax expense (benefit)	$	6.6		$	11.9		$	18.5

Deferred taxes result from temporary differences in the recognition of certain liabilities or assets for tax and financial reporting purposes. The principal components of the company’s deferred tax assets and liabilities recognized in the balance sheet are as follows:

Deferred Income Tax Assets and Liabilities

(millions) Dec. 31,	2002			2001
Deferred income tax assets (1)
Property related	$	86.8		$	87.7
Basis differences in oil and gas producing properties		(0.1	)		1.2
Alternative minimum tax credit carry forward		201.3			105.5
Other		52.2			47.6

Total deferred income tax assets		340.2			242.0

Deferred income tax liabilities (1)
Property related		(565.3	)		(522.8	)
Basis differences in oil and gas producing properties		(13.9	)		(8.9	)
Other		84.2			33.0

Total deferred income tax liabilities		(495.0	)		(498.7	)

Accumulated deferred income taxes	$	(154.8	)	$	(256.7	)

(1)

Certain property related assets and liabilities have been netted.

The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons:

Effective Income Tax Rate

(millions)	2002			2001			2000
Net income from continuing operations	$	298.2		$	273.8		$	227.5
Total income tax provision (benefit)		(38.4	)		(2.1	)		29.3

Income from continuing operations before income taxes	$	259.8		$	271.7		$	256.8

Income taxes on above at federal statutory rate of 35%	$	90.9		$	95.1		$	89.9
Increase (Decrease) due to
State income tax, net of federal income tax		4.6			7.3			7.5
Amortization of investment tax credits		(4.8	)		(4.9	)		(4.9	)
Non-conventional fuels tax credit		(107.3	)		(86.2	)		(52.1	)
Permanent reinvestment-foreign income		(8.1	)		(7.2	)		(9.3	)
AFUDC Equity		(8.7	)		(2.3	)		(0.60
Other		(5.0	)		(3.9	)		(1.2	)

Total income tax provision from continuing operations	$	(38.4	)	$	(2.1	)	$	29.3

Provision for income taxes as a percent of income from continuing operations, before income taxes		(14.8	)%		(0.8	)%		11.4	%

The provision for income taxes as a percent of income from discontinued operations was -22.4%, -36.5% and -46.1%, respectively, in 2002, 2001 and 2000. The total effective income tax rate differs from the federal statutory rate due to state income tax, net of federal income tax, the non-conventional fuels tax credit and other miscellaneous items. The actual cash paid for income taxes as required by the alternative minimum tax rules in 2002, 2001, and 2000 was $71.9 million, $52.4 million and $83.9 million, respectively.

N. Related Parties

The company and its subsidiaries had certain transactions, in the ordinary course of business, with entities in which directors of the company had interests. These transactions, primarily for legal services, were not material for 2002, 2001 and 2000. No material balances were payable as of Dec. 31, 2002 or 2001.

TPS recognized income on the non-TPS portion of notes receivable from unconsolidated affiliates in which TPS holds joint venture interests and from credit support for the TPGC joint venture. The notes receivable from unconsolidated affiliates are as follows:

Notes Receivable From Related Parties

(millions) Dec. 31,	Rate		2002		2001
Panda Energy	14.00	%	$	137.0	$	92.7
Energeticke Centrum Kladno	6.00	%		1.4		—
Mosbacher Power Partners L.P.	12.00	%		—		13.1
Mosbacher Power Partners L.P.	9.00	%		13.7		21.1
Mosbacher Power Partners L.P.	12.00	%		—		6.2
EEGSA	6.81	%(1)		11.1		10.9
TPGC—Gila River	7.79	%(1)		369.5		37.5
TPGC—Union Power	6.58	%(1)		426.3		86.7

(1)

Current rate at Dec. 31, 2002

Other Income (Expense) included pretax income from construction-related and loan agreements with Panda Energy, and interest income of $78.9 million and $32.8 million for 2002 and 2001, respectively from the other notes receivable shown on the preceeding table.

At Dec. 31, 2002, TPS’ position in the Odessa and Guadalupe power stations in Texas was in the form of a $137 million loan to a Panda Energy International subsidiary, which is a partner in Texas Independent Energy (TIE). On Jan. 3, 2003 the loan converted to an ownership interest in these projects.

TPS Arkansas Operations Company and TPS Arizona Operations Company, both wholly-owned subsidiaries of TPS, have a combined receivable from TPGC of $0.8 million as of Dec. 31, 2002.

TPS has agreed to purchase the interests of Panda Energy in the TPGC projects in 2007 for $60 million, and TECO Energy has guaranteed payment of TPS’ purchase obligation. This obligation may be accelerated if Panda Energy defaults on a bank loan for which the TPS purchase obligation is collateral or if TECO Energy permits its debt-to-capital ratio to exceed 65.0%, permits its EBITDA/interest ratio to fall below 1.5 times or defaults on the payment of indebtedness in excess of $50 million. TECO Energy’s debt-to-capital ratio at Dec. 31, 2002, was 55.9% and its EBITDA/interest ratio was 3.6 times (See Note R). Panda Energy may cancel the purchase obligation at any time prior to 2007 by paying TPS a cancellation fee that ranges from $8 million to $20 million based on the time of such cancellation.

O. Discontinued Operations

TECO Coalbed Methane, a subsidiary of TECO Energy, had developed jointly the natural gas potential in a portion of Alabama’s Black Warrior Basin. In September 2002, the company announced its intent to sell the TECO Coalbed Methane gas assets. On Dec. 20. 2002, TECO Energy sold substantially all of its coalbed methane assets in Alabama to the Municipal Gas Authority of Georgia. Proceeds from the sale were $140 million, $42 million paid in cash at closing, and a $98 million note receivable, which was paid in January 2003 (See Note U). TECO Coalbed Methane’s results were accounted for as discontinued operations for all periods reported. The gas assets are included in Property held for sale net of accumulated depreciation on the Consolidated Balance Sheets as of Dec. 31, 2001. Operating revenues from TECO Coalbed Methane were $39.7 million, $55.0 million and $43.0 million, and pretax operating income was $14.9 million, $24.3 million and $12.6 million for the years ended Dec. 31, 2002, 2001 and 2000, respectively.

TECO Coalbed Methane utilized the successful efforts method to account for its gas operations, in which expenditures for unsuccessful exploration activities were expensed currently.

Capitalized costs were amortized on the unit-of-production method using estimates of proven reserves. Investments in unproven properties and major development projects were not amortized until proven reserves associated with the projects could be determined or until impairment occurred.

Aggregate capitalized costs related to producing wells at Dec. 31, 2001 were $220.8 million. Net proven reserves at Dec. 31, 2001 were as follows:

Net Proven Reserves—Coalbed Methane Gas

(billion cubic feet)	2001
Proven reserves, beginning of year	181.7
Production	(15.0	)
Revisions of previous estimates	0.4

Proven reserves, end of year	167.1

Number of wells	682

P. Earnings Per Share

In 1997, the FASB issued FAS 128, Earnings per Share, which requires disclosure of basic and diluted earnings per share and a reconciliation (where different) of the numerator and denominator from basic to diluted earnings per share. The reconciliation of basic and diluted earnings per share is shown as follows:

Earnings Per Share

(millions, except per share amounts)	2002			2001			2000
Numerator
Net Income from continuing operations, basic	$	298.2		$	273.8		$	227.5
Effect of contingent performance shares		—			—			(1.9	)

Net Income from continuing operations, diluted	$	298.2		$	273.8		$	225.6

Net Income, basic	$	330.1		$	303.7		$	250.9
Effect of contingent performance shares		—			—			(1.9	)

Net Income, diluted	$	330.1		$	303.7		$	249.0

Denominator
Average number of shares outstanding—basic		153.2			134.5			125.9
Plus: incremental shares for assumed conversions: Stock options at end of period and contingent performance shares		2.1			4.2			3.3
Less: Treasury shares which could be purchased		(2.0	)		(3.3	)		(2.9	)

Average number of shares outstanding—diluted		153.3			135.4			126.3

Earnings per share from continuing operations
Basic	$	1.95		$	2.04		$	1.81
Diluted	$	1.95		$	2.02		$	1.79

Earnings per share
Basic	$	2.15		$	2.26		$	1.99
Diluted	$	2.15		$	2.24		$	1.97

For the year ended Dec. 31, 2002, stock options for 4.5 million shares and 14.9 million common shares issuable under the purchase contract associated with the mandatorily convertible equity units issued in January 2002 were excluded from the computation of diluted earnings per share due to their antidilutive effect. For the year ended Dec. 31, 2001, stock options for 1.2 million shares were excluded from the computation of diluted earnings per share due to their antidilutive effect.

Q. Segment Information

TECO Energy is an electric and gas utility holding company with significant diversified activities. The management of TECO Energy determined its reportable segments based on each subsidiary’s contribution of revenues, net income and total assets. All significant intercompany transactions are eliminated in the consolidated financial statements of TECO Energy but are included in determining reportable segments in accordance with FAS 131, Disclosures about Segments of an Enterprise and Related Information. In December 2002, TECO Energy sold the assets of TECO Coalbed Methane. Information presented here excludes TECO Coalbed Methane’s results, which are reflected in the consolidated financial statements as discontinued operations.

Segment Information

(millions)	Revenues(1)(2)			Net Income (1)(3)			Depreciation (1)		Assets at Dec. 31,			Capital Expenditures
2002
Tampa Electric	$	1,583.2	(4)	$	171.8	(9)	$	189.8	$	3,737.0		$	632.2
Peoples Gas System		318.1			24.2	(10)		30.5		571.7			53.5
TECO Power Services		309.8	(5)		34.1	(11)		28.1		2,875.0	(15)(16)		299.9
TECO Transport		254.6	(6)		21.0	(12)		22.3		355.1			25.2
TECO Coal		317.1	(7)		76.5	(13)		31.4		283.5			48.2
Other unregulated businesses		122.1	(8)		6.8	(14)		1.3		312.4	(17)(18)		3.0

		2,904.9			334.4			303.4		8,134.7			1,062.0
Other and eliminations		(229.1	)		(36.2	)		—		503.1	(19)		3.2	(19)

TECO Energy consolidated	$	2,675.8		$	298.2		$	303.4	$	8,637.8		$	1,065.2

2001
Tampa Electric	$	1,412.7	(4)	$	154.0	(9)	$	173.4	$	3,315.5		$	426.3
Peoples Gas System		352.9			23.1	(10)		27.9		528.9			73.0
TECO Power Services		287.1	(5)		26.9	(11)		28.4		1,935.4	(15)(16)		397.5
TECO Transport		274.9	(6)		27.6	(12)		24.1		333.1			38.8
TECO Coal		303.4	(7)		59.0	(13)		28.3		258.5			25.8
Other unregulated businesses		106.9	(8)		4.0	(14)		6.1		295.5	(17)(18)		(0.1	)

		2,737.9			294.6			288.2		6,666.9			961.3
Other and eliminations		(249.8	)		(20.8	)		—		96.5	(19)		4.6	(19)

TECO Energy consolidated	$	2,488.1		$	273.8		$	288.2	$	6,763.4		$	965.9

2000
Tampa Electric	$	1,353.8	(4)	$	144.5	(9)	$	161.6	$	2,997.1		$	267.1
Peoples Gas System		314.5			21.8	(10)		25.8		513.3			82.2
TECO Power Services		199.1	(5)		22.8	(11)		18.5		1,350.6	(15)(16)		243.5
TECO Transport		269.8	(6)		29.2	(12)		22.0		311.3			21.1
TECO Coal		232.8	(7)		33.5	(13)		26.9		246.3			64.0
Other unregulated businesses		81.8	(8)		1.2	(14)		3.2		213.3	(17)(18)		6.9

		2,451.8			253.0			258.0		5,631.9			684.8
Other and eliminations		(228.7	)		(25.5	)		—		142.4	(19)		3.6	(19)

TECO Energy consolidated	$	2,223.1		$	227.5		$	258.0	$	5,774.3		$	688.4

(1)

From continuing operations. Revenues, net income and depreciation for all periods have been adjusted to reflect the reclassification of TECO Coalbed Methane results as discontinued operations.

(2)

Revenues for all periods have been adjusted to reflect the presentation of energy marketing related revenues on a net basis and the reclassification of earnings from equity investments from Revenues to Other income.

(3)

Segment net income is reported on a basis that includes internally allocated financing costs. Internally allocated costs for 2002, 2001, and 2000 were at pretax rates of 7%, 7%, and 6.75%, respectively, based on the average investment in each subsidiary.

(4)

Revenues from sales to affiliates were $ 34.4 million, $32.6 million and $32.4 million in 2002, 2001 and 2000, respectively.

(5)

Revenues from sales to affiliates were $ 51.4 million, $65.0 million and $67.6 million in 2002, 2001 and 2000, respectively.

(6)

Revenues from sales to affiliates were $110.7 million, $123.2 million and $118.0 million in 2002, 2001 and 2000, respectively.

(7)

Revenues from sales to affiliates were $0.7 million, $5.1 million and $4.3 million in 2002, 2001 and 2000, respectively.

(8)

Revenues from sales to affiliates were $31.9 million, $23.8 million and $6.5 million in 2002, 2001 and 2000, respectively.

(9)

Net income includes net interest expense of $51.5 million, $60.8 million and $67.4 million in 2002, 2001 and 2000, respectively. Net income also includes provisions for income taxes of $85.7 million, $83.4 million and $82.5 million, respectively, for the same periods.

(10)

Net income includes net interest expense of $14.7 million, $14.3 million and $12.6 million in 2002, 2001 and 2000, respectively. Net income also includes provisions for income taxes of $14.7 million, $14.2 million and $13.3 million, respectively, for the same periods.

(11)

Net income includes net interest expense of $57.2 million, $51.8 million and $23.0 million for 2002, 2001 and 2000, respectively, of which $102.6 million, $54.1 million and $23.0 million for the same periods was internally allocated financing costs (see Note A). Net income also includes provisions for income taxes of $9.2 million and $0.7 million for 2002 and 2001, respectively, and an income tax benefit of $0.6 million for 2000.

(12)

Net income includes net interest expense of $6.3 million, $8.9 million and $6.5 million for 2002, 2001 and 2000, respectively, of which $1.7 million, $0.7 million and $0.9 million for the same periods was internally allocated financing income. Net income also includes provisions for income taxes of $10.8 million, $14.2 million and $16.2 million, respectively for the same periods.

(13)

Net income includes internally allocated financing costs of $8.1 million, $7.6 million and $6.5 million for 2002, 2001 and 2000, respectively. Net income also includes income tax benefits of $22.9 million, $19.0 million and $14.8 million, respectively, for the same periods.

(14)

Net income includes internally allocated financing costs of $4.5 million, $4.4 million and $2.7 million for 2002, 2001 and 2000, respectively. Net income also includes provisions for income taxes of $0.3 million, $3.1 million and $0.9 million, respectively, for the same periods.

(15)

Total assets include $97.4 million, $120.4 million and $145.5 million in investments in unconsolidated affiliates at Dec. 31, 2002, 2001 and 2000, respectively. Total assets also includes $972.6 million, $286.4 and $383.1 million in other non-current investments at Dec. 31, 2002, 2001 and 2000, respectively .

(16)

Total assets include $154.5 million, $129.4 million and $65.7 million in goodwill net of amortization at Dec. 31, 2002, 2001 and 2000, respectively.

(17)

Total assets include $51.8 million, $52.5 million and $50.4 million in investments in unconsolidated affiliates at Dec. 31, 2002, 2001 and 2000, respectively.

(18)

Total assets include $39.1 million, $36.4 million and $27.4 million in goodwill net of amortization at Dec. 31, 2002, 2001 and 2000, respectively.

(19)

Total assets and capital expenditures for all periods include amounts for the discontinued operations of TECO Coalbed Methane.

Tampa Electric Company provides retail electric utility services to almost 598,000 customers in West Central Florida. Its Peoples Gas System division is engaged in the purchase, distribution and marketing of natural gas for more than 281,000 residential, commercial, industrial and electric power generation customers in the state of Florida.

TECO Transport, through its wholly-owned subsidiaries, transports, stores and transfers coal and other dry bulk commodities for third parties and Tampa Electric. TECO Transport’s subsidiaries operate on the Mississippi, Ohio and Illinois rivers, in the Gulf of Mexico and worldwide.

TECO Coal, through its wholly-owned subsidiaries, owns mineral rights and owns or operates surface and underground mines and coal processing and loading facilities in Kentucky, Tennessee and Virginia. In 2000, these subsidiaries began operating two synthetic fuel processing facilities, whose production qualifies for the non-conventional fuels tax credit. With plans to continue growth in the production and sales of synfuel, TECO Coal has formed a new LLC and has transferred the synfuel units into this LLC effective Jan. 1, 2003. Selling partial interest in the LLC will facilitate efforts to maximize production as well as increase overall cash flow. TECO Coal’s subsidiaries sell their coal production to third parties.

TPS has subsidiaries that have interests in independent power projects in Florida, Virginia, Texas, Arkansas, Mississippi, Arizona, Hawaii and Guatemala, and transmission and distribution facilities in Guatemala. TPS also has investments in unconsolidated affiliates that participate in independent power projects in other parts of the U.S. and the world.

TECO Energy’s other diversified businesses are engaged in the marketing of natural gas, and energy services and engineering. Also included is the company’s investment in the propane business.

Foreign Operations

TPS has independent power operations and investments in Guatemala.

TPS, through its subsidiaries, has a 96 percent ownership interest and operates a 78-megawatt power station that supplies energy to EEGSA, an electric utility in Guatemala, under a U.S. dollar-denominated power sales agreement.

At Dec. 31, 2002, TPS, through a wholly-owned subsidiary, had a 100 percent ownership interest in a 120-megawatt power station and in transmission facilities in Guatemala. The plant provides capacity under a U.S. dollar-denominated power sales agreement to EEGSA.

TPS, through a subsidiary, owns a 30 percent interest in a consortium that includes Iberdrola, an electric utility in Spain, and Electricidade de Portugal, an electric utility in Portugal. The consortium owns an 80.9 percent interest in EEGSA.

Total assets at Dec. 31, 2002, 2001 and 2000 included $415.9 million, $454.2 million and $442.6 million, respectively, related to these Guatemalan operations and investments. Revenues included $88.5 million, $79.9 million and $69.0 million for the years ended Dec. 31, 2002, 2001 and 2000, respectively, and operating income included $33.0 million, $38.0 million and $23.7 million for the same periods from these Guatemalan operations and investments.

R. Commitments and Contingencies

Capital Investments

TECO Energy has made certain commitments in connection with its continuing capital improvements program. At Dec. 31, 2002, these forecasted capital investments total approximately $2.0 billion for the years 2003 through 2007 and are summarized as follows.

Forecasted-Capital Investments

(millions)	2003		2004		2005 – 2007		Total 2003 – 2007
Florida operations	$	272	$	266	$	725	$	1,263
Independent power		424		25		75		524
Transportation		15		21		61		97
Other		16		23		55		94

	$	727	$	335	$	916	$	1,978

For 2003, Tampa Electric expects to spend $232 million, consisting of $78 million for the repowering project at the Gannon Station, and $154 million to support system growth and generation reliability. Tampa Electric’s estimated capital expenditures over the 2004-2007 period are projected to be $841 million, including $67 for the Gannon repowering project. At the end of 2002, Tampa Electric had outstanding commitments of about $119 million for the Gannon repowering project.

TPS expects to invest $424 million in 2003 for completion of the Union and Gila River power stations and $100 million in 2004 through 2006, mainly for the completion of the Dell and McAdams power stations. Estimates for TPS include net contributions to projects of unconsolidated affiliates and other investments of $393 million. TPS had outstanding commitments at Dec. 31, 2002 of approximately $384 million related to the Union and Gila River power stations.

The other unregulated companies expect to invest $31 million in 2003 and $160 million during 2004 through 2007, mainly for normal renewal and replacement capital.

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 Dec. 31, 2002, Tampa Electric Company has estimated its ultimate financial liability to be $20 million, and this amount has been accrued in the company’s financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, 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.

Long Term Operating Lease Commitments

TECO Energy has commitments under long-term operating leases, primarily for building space, office equipment and heavy equipment, marine assets at TECO Transport, and certain equipment at TPS’ Hardee Power Station. On Dec. 30, 2002 TECO Transport completed a sales leaseback transaction to be accounted for as an operating lease covering one ocean-going tug and barge, five river towboats and 49 river barges. On Dec. 21, 2001, TECO Transport sold three ocean-going barges and one ocean-going tug boat in a sales leaseback transaction to be accounted for as an operating lease. Both lease terms are 12 years with early buyout options after 5 years. TPS completed a transaction on Dec. 29, 2000, where certain equipment at its Hardee Power Station was sold to a third party and leased back under a 12-year operating lease.

Total rental expense for these operating leases, included in the Consolidated Statements of Income for the years ended Dec. 31, 2002, 2001 and 2000 was $26.1 million, $20.4 million and $17.6 million, respectively. The following is a schedule of future minimum lease payments at Dec. 31, 2002 for all operating leases with noncancelable lease terms in excess of one year:

Future Minimum Lease Payments For Operating Leases

Year ended Dec. 31:	Amount (millions)
2003	$	27.4
2004		26.5
2005		23.3
2006		20.7
2007		17.9
Later Years		107.1

Total minimum lease payments	$	222.9

Guarantees and Letters of Credit

TECO Energy company has outstanding letters of credit of $185.0 million at Dec. 31, 2002, which guarantee performance to third parties related to debt service, major maintenance requirements and various trade activities. The company also has financial guarantees of $755.6 million at Dec. 31, 2002, primarily for fuel purchases, energy management and construction related debt for projects in which TPS is a participant. Most of the guarantees are renewable annually. In addition, TECO Energy has guaranteed a $375 million equity bridge loan and the $60 million construction undertaking related to the Gila River and Union power stations. A summary of TECO Energy’s letters of credit and guarantees are as follows:

Letters of Credit and Guarantees

($ in millions) Letters of Credit and Guarantees for the Benefit of	2003		2004		After 2005-2007		2007		Total		Liabilities Recognized at Dec. 31, 2002
Tampa Electric
Letters of credit	$	—	$	—	$	—	$	0.9	$	0.9	$	—

TECO Power Services
Letters of credit		128.0		27.1				24.7		179.8
Guarantees:
Debt related								15.7		15.7
Fuel purchase/energy management								443.9		443.9		10.0
Construction/Investment related		435.0				60.0		5.0		500.0

		563.0		27.1		60.0		489.3		1,139.4		10.0

TECO Transport
Letters of credit		—		—		—		1.5		1.5		—

TECO Coal
Letters of credit								0.1		0.1
Guarantees: Fuel purchase related								1.5		1.5		1.5

		—		—		—		1.6		1.6		1.5

Other unregulated subsidiaries
Letters of credit								2.7		2.7
Guarantees:
Debt related								8.0		8.0
Fuel purchase/energy management								221.5		221.5		46.4

		—		—		—		232.2		232.2		46.4

	$	563.0	$	27.1	$	60.0	$	725.5	$	1,375.6	$	57.9

Financial Covenants

A summary of TECO Energy’s significant financial covenants is as follows:

TECO Energy Significant Financial Covenants

(millions) Instrument	Financial Covenant(1)	Requirement/ Restriction	Calculation at Dec. 31, 2002
Tampa Electric
Mortgage bond indenture	Dividend restriction	Cumulative distributions cannot exceed cumulative net income plus $4	$189 unrestricted
PGS senior notes	EBIT/interest	Minimum of 2.0 times	3.7 times
	Restricted payments	Shareholder equity at least $500	$1,838
	Funded debt/capital	Cannot exceed 65%	44.8%
	Sale of assets	Less than 20% of total assets	0%
Credit facility	Debt/capital	Cannot exceed 60%	43.9%
	EBITDA/interest	Minimum of 2.5 times	7.8 times
TECO Energy
Credit facilities	Debt/capital	Cannot exceed 65%	55.9%
$380 million note indenture(2)	Various	—	—
TECO/Panda guarantees(3)	Debt/capital	Cannot exceed 65%	55.9%
	EBITDA/interest	Minimum of 3.0 times	3.6 times
	Minimum ratings	BBB and Baa3, or BBB- and Baa2	BBB- and Baa2
TPS purchase	Debt/capital	Cannot exceed 65%	55.9%
obligation guarantee	EBITDA/interest	Minimum of 1.5 times	3.6 times
TECO Diversified
Energy management services agreement guarantee	Consolidated tangible net worth Consolidated funded debt	Minimum of $200 Cannot exceed 60%	$575 19.1%
Coal supply agreement guarantee	Dividend restriction	Net worth not less than $200 or $446 (40% of tangible net assets)	$536

(1)

As defined in applicable instrument.

(2)

Indenture contains covenants which would apply only if either (a) Notes are rated below BBB- by S&P or below Baa3 by Moody’s or (b) Notes are rated below Special Ratings Trigger (minimum of BBB- by S&P and Baa2 by Moody’s or BBB by S&P and Baa3 by Moody’s) if TECO Energy Construction Undertakings for the TECO/Panda projects are not substantially discharged. These covenants include Limitation on Restricted Payments, Limitations on Certain Liens and Limitation on Indebtedness.

(3)

Includes Equity Bridge, Equity Contribution and Construction Undertaking Guarantees related to the TPGC projects.

Other Contingencies

In December 2001, Enron Corp., a large energy trading and services company, filed for protection under the U.S. Bankruptcy Code. TECO Energy announced it believed it had exposure in operations from trade payables and other trading positions due to the Enron bankruptcy of $3.5 million or less after-tax at its subsidiaries TPS, PGS and Prior Energy. TECO Energy has negotiated an agreement with Enron, pending approval of the Creditors Committee, to settle the previously reported $3.5 million of potential trade payables exposure as a result of the Enron bankruptcy. The net financial impact of the agreement is reflected in consolidated net income and no future financial impact is expected.

In addition to the financial and non-financial guarantees listed above, TECO Energy and its subsidiaries include indemnity clauses, in the normal course of business, in certain agreements with vendors and other third parties. Such clauses may provide indemnification to the counter-party for certain amounts such as legal fees, environmental remediation costs and other similar costs arising from potential future events or changes in laws or regulations. As these agreements cover a variety of goods and services, and have varying triggering events dependent on actions by third parties, TECO Energy is unable to estimate the maximum potential future exposure under these clauses. As claims are made or changes in laws or regulations indicate, an amount related to the indemnification is reflected in the financial statements.

S. Mergers and Acquisitions

In May 2002, TPS purchased Mosbacher Power Partners’ interest in TM Power Ventures (TMPV) for $29.3 million. The majority of the purchase price was allocated to TMPV’s investment in the 312-megawatt Commonwealth Chesapeake Power Station located on the Delmarva Peninsula in Virginia, and has been recorded as an increase in goodwill. The acquisition increased TPS’ ownership interest in TMPV to 100 percent.

In November 2001, TECO Solutions acquired Prior Energy Corporation, a leading natural gas management company serving customers in Alabama, Florida, Georgia, Louisiana, Mississippi, North Carolina, South Carolina, Tennessee and Texas. Prior Energy handles all facets of natural gas energy management services, including natural gas purchasing and marketing. The company has an established market base in the Southeast and one of the top customer service reputations in the region. The acquisition was accounted for by the purchase method of accounting and, accordingly, the results of operations of Prior Energy are included as part of TECO Solutions’ results beginning Nov. 1, 2001. The final working capital adjustment and purchase price allocation was completed in 2002. The total cost of the acquisition was $23.0 million plus a net working capital payment of $6.4 million. Goodwill of $9.6 million was recorded, representing the excess of purchase price over the fair market value of assets acquired. Under FAS 141, effective for all business combinations initiated after June 30, 2001, goodwill is no longer subject to amortization. Net intangible assets of $39.8 million were recorded, representing the value of customer backlog and supply agreements as well as the open cash flow hedges as of Nov. 1, 2001, which are being amortized over 2001 through 2004.

In March 2001, TPS acquired the Frontera Power Station located near McAllen, Texas, accounting for the transaction using the purchase method of accounting. This 477-megawatt, natural gas-fired combined-cycle plant, originally developed by CSW Energy (CSW), began commercial operation in May 2000. As a condition of the merger of Central & South West Corporation, CSW’s parent company, with American Electric Power Company, Inc., the FERC required CSW to divest its ownership in this facility. The total cost of the acquisition was $265.3 million. Goodwill of $70.4 million, representing the excess of purchase price over the fair market value of assets acquired, was recorded, and was amortized on a straight-line basis over 40 years until the requirements of FAS 141 became effective on Jan. 1, 2002 (See Note C). The results of operations of Frontera Power Station are included as part of TPS’ results beginning March 16, 2001.

The following pro forma disclosures include Prior Energy and the Frontera Power Station as if they had been included in TECO Energy’s financial statements for the years ended Dec. 31, 2001 and 2000.

Pro Forma Disclosure — Mergers and Acquisitions

	Actual		Pro Forma
Year ended Dec. 31,	2002		2002		2000
Revenues (millions)	$	2,675.8	$	2,557.4	$	2,308.6
Net income from continuing operations (millions)	$	298.2	$	270.4	$	230.5
Earnings per share from continuing operations – basic	$	1.95	$	2.01	$	1.83

This pro forma information is not necessarily indicative of the operating results that would have occurred had the acquisitions been completed as of the dates indicated, nor are they indicative of future operating results.

In October 2001, TECO BGA, a unit of TECO Solutions, purchased a district cooling business from FPL Energy Services, a subsidiary of FPL Group. The acquisition includes a 12,000-ton design capacity cooling plant located in downtown Miami. This acquisition provides TECO BGA with a stronger presence in the growing South Florida energy market, long-term contract business, a franchise agreement with the city of Miami and the potential for expansion. The acquisition was accounted for by the purchase method of accounting and, accordingly, its results of operations are included as part of TECO BGA’s results beginning Oct. 25, 2001. The total cost of the acquisition was $12.5 million. No goodwill was recorded for the acquisition. The acquisition was not material to the financial statements; no pro forma disclosures are presented.

On Nov. 1, 2000, TECO Coal acquired all of the outstanding stock of Perry County Coal for $14.9 million, comprised of $12.1 million in cash and $2.8 million in notes. Perry County Coal owns or controls more than 23 million tons of low-sulfur reserves, and operates both deep and surface contract mines. The acquisition was accounted for by the purchase method of accounting and, accordingly, the results of operations and assets of Perry County Coal are included as part of TECO Coal’s results beginning Nov. 1, 2000. The acquisition was not material to the financial statements; no pro forma disclosures are presented.

In September 2000, TECO Energy acquired BCH Mechanical, Inc. and its affiliated companies (“BCH”) accounting for the transaction using the purchase method of accounting. BCH is one of the leading mechanical contracting firms in Florida. TECO Energy purchased a combination of stock and assets of the BCH companies for $34.8 million, comprised of $26.1 million in cash, $2.9 million in notes, and 233,819 shares of TECO Energy common stock. Goodwill of $25.9 million representing the excess of purchase price over the fair market value of assets acquired was recorded, and was amortized on a straight-line basis over 20 years, until the requirements of FAS 141 became effective on Jan. 1, 2002 (See Note C). The results of operations of BCH are included as part of TECO Energy’s results beginning Sept. 1, 2000. The acquisition was not material to the financial statements; no pro forma disclosures are presented.

In connection with this transaction, TECO Solutions was formed to support TECO Energy’s strategy of offering customers a comprehensive and competitive package of energy services and products. Operating companies under TECO Solutions include TECO Energy Services (formerly TECO BGA and BCH Mechanical), TECO Partners, TPV, TECO Gas Services, Prior Energy and TECO Properties.

In February 2000, TECO Energy entered into an agreement to form US Propane, a joint venture to combine its Peoples Gas Company (PGC) propane operations with the propane operations of Atmos Energy Corporation, AGL Resources Inc. and Piedmont Natural Gas Company, Inc. Through a series of transactions completed Aug. 10, 2000, US Propane combined its propane operations with those of Heritage Propane Partners, L.P. US Propane now owns the general partner interest and 29 percent of the limited partnership interests of Heritage Propane Partners. TECO Energy through its wholly-owned subsidiary TPV, is accounting for its interest in US Propane under the equity method of accounting. As a result of these transactions, TPV also received $19.3 million in cash and recognized a pretax gain of $13.6 million ($8.3 million after-tax) on the sale of PGC assets and liabilities to the extent acquired by US Propane and Heritage Propane Partners.

T. New Accounting Pronouncements

Accounting for Asset Retirement Obligations

In July 2001, the FASB issued FAS 143, Accounting for Asset Retirement Obligations, which requires the recognition of a liability at fair value for an asset retirement obligation in the period in which it is incurred. Retirement obligations associated with long-lived assets included within the scope of FAS 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. Retirement obligations are included in the scope of the standard only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.

When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its future value. The corresponding amount capitalized at inception is depreciated over the useful life of the asset. The liability must be revalued each period based on current market prices. FAS 143 is effective for fiscal years beginning after June 15, 2002. The company estimates that the adoption of FAS 143 will result in a non-cash increase to net property, plant and equipment of approximately $8.0 million, a non-cash net increase to asset retirement obligation of approximately $10.0 million, and as a cumulative effect of change in accounting principle, a non-cash pretax charge of approximately $2.0 million.

Exit or Disposal Costs

TECO Energy opted to adopt early FAS 146 in 2002. Early retirements were accepted by 52 employees at Tampa Electric Company’s electric division in mid-2002. Cost associated with this program were approximately $6.3 million and were recognized in operation expenses in the third quarter of 2003. In the fourth quarter of 2002, TECO Energy initiated an additional restructuring program that impacted approximately 200 employees. This program includes retirements, the elimination of positions and other cost control measures. The total costs associated with this program, including severance, salary continuance through the end of 2002 and other benefit costs, were approximately $13 million and were recognized in the fourth quarter.

Gains and Losses on Energy Trading Contracts

On Oct. 25, 2002, the Emerging Issues Task Force released EITF 02-3, Recognition and Reporting of Gains and Losses on Energy Trading Contracts Under Issues No. 98-10 and 00-17, which 1) precludes mark-to-market accounting for energy trading contracts that are not derivatives pursuant to FAS 133, 2) requires that gains and losses on all derivative instruments within the scope of FAS 133 be presented on a net basis in the income statement if held for trading purposes, and 3) limits the circumstances in which a reporting entity may recognize a “day one” gain or loss on a derivative contract. The measurement provisions of the issue are effective for all fiscal periods beginning after Dec. 15, 2002. The net presentation provisions are effective for all financial statements issued after Dec. 15, 2002. In accordance with the recommended transition provisions, TECO Energy reclassified certain amounts in prior periods to present gains and losses on a net basis (see Note A). The adoption of the measurement provisions is not anticipated to have a material impact.

100

Guarantees

In November 2002, the FASB issued Interpretation No. (FIN) 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of others (an interpretation of FAS No. 5, 57, and 107 and rescission of FAS Interpretation No. 34), which modifies the accounting and enhances the disclosure of certain types of guarantees. FIN 45 requires that upon issuance of certain guarantees, the guarantor must recognize a liability for the fair value of the obligation it assumes under the guarantee. FIN 45’s provisions for the initial recognition and measurement are to be applied to guarantees issued or modified after Dec. 31, 2002. The disclosure requirements are effective for financial statements of annual periods that end after Dec. 15, 2002 (see Note R).

Stock-Based Compensation

In December 2002, the FASB issued FAS 148, Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment of FASB Statement No. 123. This standard amends FAS 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for companies that voluntarily change to the fair value based method of accounting for stock-based employee compensation. It also requires prominent disclosure about the effects on reported net income of the company’s accounting policy decisions with respect to stock-based employee compensation in both annual and interim financial statements. The transition provisions and annual disclosure requirements are effective for all fiscal years ending after Dec. 15, 2002, while the interim period disclosure requirements are effective for all interim periods beginning after Dec. 15, 2002. The adoption of the disclosure provisions of this standard does not have a material impact.

Consolidation of Variable Interest Entities

The equity method of accounting is used to account for investments in partnership arrangements in which TECO Energy or its subsidiary companies do not have a majority ownership or exercise control. On Jan. 17, 2003, the FASB issued FASB Interpretation (FIN) No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51, which imposes a new approach in determining if a reporting entity should consolidate certain legal entities, including partnerships, limited liability companies, or trusts, among others, collectively defined as variable interest entities or VIEs. A legal entity is considered a VIE if it does not have sufficient equity at risk to finance its own activities without relying on financial support from other parties. Additional criteria must be applied to determine if this condition is met or if the equity holders, as a group, lack any one of three stipulated characteristics of a controlling financial interest. If the legal entity is a VIE, then the reporting entity determined to be the primary beneficiary must consolidate it. Even if a reporting entity is not obligated to consolidate a VIE, then certain disclosures must be made about the VIE if the reporting entity has a significant variable interest. Certain transition disclosures are required for all financial statements issued after Jan. 31, 2003. The on-going disclosure and consolidation requirements are effective for all interim financial periods beginning after June 15, 2003.

Based on a preliminary review, TECO Energy believes it is reasonably possible that FIN 46 may impact the accounting for certain unconsolidated affiliates. Management is continuing to assess the extent of the relationships and obtain adequate information upon which to base appropriate conclusions. Below is a discussion of the legal entities existing as of Dec. 31, 2002 that TECO Energy considers to be possibly subject to either 1) additional disclosure requirements or 2) consolidation by the company, in accordance with FIN 46.

TPS entered into a joint venture, TPGC, to build, own and operate the Union and Gila River power stations. As of Dec. 31, 2002, TPGC is a development stage partnership that may meet the definition of a VIE in accordance with FIN 46. The third-party debt financing at TPGC is non-recourse and does not create an estimated loss exposure to TECO Energy. The estimated maximum loss exposure is approximately the current and guaranteed equity investment in the partnership. (See Notes A, N and R.)

TPS completed a transaction whereby certain equipment at the Hardee Power Station was sold to a third party (the Lessor) and leased back under an operating lease agreement with an initial term of 12 years. The original cost of the equipment was $46.6 million. The sole purpose of the Lessor is to own and lease back the equipment to Hardee Power. The Lessor may be a VIE in accordance with FIN 46. The lease financing arrangement includes $41.6 million of subordinated debt and $1.4 million of equity contributed by an unrelated third party. If the Lessor were to be consolidated, TPS estimates that it would incur after-tax incremental expenses of approximately $9.5 million over the 12 year term of the lease. (See Note R.)

TECO Properties formed two limited liability companies with project developers which may meet the definition of a VIE. Hernando Oaks, LLC was formed by TECO Properties with the Pensacola Group to buy and develop 627 acres of land in Hernando County, Florida into a residential golf community comprised of an 18-hole golf course and 975 single-family lots for sale to homebuilders. Hernando Oaks, LLC had total assets at Dec. 31, 2002 of $18.9 million. TECO Properties’ estimated maximum loss exposure in this project is approximately $9.7 million.

B-T One, LLC is a limited liability company formed by TECO Properties with Boyd Development Co., the project developer, to buy 592 acres of land in Ocala, Florida and to develop and sell 585 single-family lots to homebuilders. B-T One, LLC had total assets at Dec. 31, 2002 of $13.1 million. TECO Properties’ estimated maximum loss exposure in this project is approximately $7.5 million.

101

TECO Propane Ventures (TPV) has an investment in a partnership formed to combine propane operations with the propane operations of three third-party entities. The partnership may meet the definition of a VIE as established in FIN 46. At Dec. 31, 2002, the estimated maximum loss exposure faced by TPV is approximately $44.6 million. (See Note S.)

TECO Energy Services (formerly TECO BGA) formed a partnership to construct, own and operate a water cooling plant to produce and distribute chilled water to customers via a local distribution loop for use, primarily, in air conditioning systems. The partnership may meet the definition of a VIE in accordance FIN 46. The estimated maximum loss exposure associated with this partnership is approximately $3.6 million as of Dec. 31, 2002.

Subsequently, in January 2002, TECO Energy sold 17.965 million units of mandatorily convertible equity units in the form of 9.5% equity units at $25 per unit. Each equity unit consisted of $25 in principal amount of a trust preferred security of TECO Capital Trust II (Trust II), a Delaware business trust formed for the purpose of issuing these securities. Trust II may meet the definition of a VIE in accordance with FIN 46. The estimated maximum loss exposure is not expected to be incrementally significant to obligations currently recognized by TECO Energy for the activities of either Trust I or Trust II. (See Note G.)

As a result of the conversion of a loan to a Panda Energy International subsidiary on Jan. 3, 2003, TPS has an equity interest in the TIE partnership (See Note N). The TIE partnership owns and operates the Odessa and Guadalupe power stations in Texas. The partnership may be a VIE in accordance with FIN 46. The estimated maximum loss exposure is approximately $137 million, representing TPS’ equity investment as of Jan. 3, 2003.

U. Subsequent Event

On Jan. 30, 2003, TECO Energy received $98.1 million in cash for the repayment of a note receivable from the Municipal Gas Authority of Georgia, related to the sale of its coalbed methane assets on Dec. 20, 2002.

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V. Quarterly Data (unaudited)

Financial data by quarter is as follows: Quarter ended	March 31		June 30		Sept. 30		Dec. 31
2002
Revenues(1)	$	606.6	$	677.7	$	731.0	$	660.5
Income from operations(1)	$	89.2	$	97.8	$	142.5	$	59.5
Net income(1)
Net income from continuing operations	$	69.9	$	80.9	$	112.8	$	34.6
Net income	$	75.4	$	85.7	$	118.9	$	50.1
Earnings per share (EPS)—basic
EPS from continuing operations	$	0.50	$	0.56	$	0.72	$	0.20
EPS	$	0.54	$	0.59	$	0.76	$	0.29
Earnings per share (EPS)—diluted
EPS from continuing operations	$	0.50	$	0.56	$	0.72	$	0.20
EPS	$	0.54	$	0.59	$	0.76	$	0.29
Dividends paid per common share(2)	$	0.345	$	0.355	$	0.355	$	0.355
Stock price per common share(3)
High	$	28.940	$	29.050	$	24.710	$	16.480
Low	$	23.400	$	22.700	$	14.200	$	10.020
Close	$	28.630	$	24.750	$	15.880	$	15.470
2001
Revenues(1)	$	641.3	$	613.2	$	659.6	$	574.0
Income from operations(1)	$	103.0	$	95.4	$	131.7	$	68.1
Net income(1)
Net income from continuing operations	$	62.1	$	61.8	$	90.8	$	59.1
Net income	$	69.7	$	71.9	$	97.3	$	64.8
Earnings per share (EPS)—basic
EPS from continuing operations	$	0.48	$	0.46	$	0.67	$	0.43
EPS	$	0.54	$	0.53	$	0.72	$	0.47
Earnings per share (EPS)—diluted
EPS from continuing operations	$	0.47	$	0.44	$	0.66	$	0.42
EPS	$	0.53	$	0.52	$	0.71	$	0.47
Dividends paid per common share(2)	$	0.335	$	0.345	$	0.345	$	0.345
Stock price per common share(3)
High	$	32.125	$	32.970	$	31.650	$	28.300
Low	$	26.100	$	28.780	$	25.530	$	24.750
Close	$	29.960	$	30.500	$	27.100	$	26.240

(1)

Millions.

(2)

Dividend paid on TECO Energy common stock.

(3)

Trading prices for common shares.

103

TAMPA ELECTRIC COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

		Page No.
Report of Independent Certified Public Accountants		105

Consolidated Balance Sheets, Dec. 31, 2002 and 2001		106-107

Consolidated Statements of Income for the years ended Dec. 31, 2002, 2001 and 2000		108

Consolidated Statements of Comprehensive Income for the years ended Dec. 31, 2002, 2001 and 2000		108

Consolidated Statements of Cash Flows for the years ended Dec. 31, 2002, 2001 and 2000		109

Consolidated Statements of Retained Earnings for the years ended Dec. 31, 2002, 2001 and 2000		110

Consolidated Statements of Capitalization, Dec. 31, 2002 and 2001		110-112

Notes to Consolidated Financial Statements		113-125

Financial Statement Schedule II – Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2002, 2001 and 2000		131

Signatures		135

Certifications		136-137

All other financial statement schedules have been omitted since they are not required, are inapplicable or the required information is presented in the financial statements or notes thereto.

104

REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

To the Board of Directors and Shareholder of Tampa Electric Company

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Tampa Electric Company and its subsidiaries, (a wholly owned subsidiary of TECO Energy, Inc.) at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers, LLP

Tampa, Florida

January 22, 2003

105

TAMPA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

Assets (millions) Dec. 31,	2002			2001
Property, Plant and Equipment
Utility plant in service
Electric	$	4,310.8		$	4,112.3
Gas		746.7			699.4
Construction work in progress		768.5			404.4

Property, plant and equipment, at original costs		5,826.0			5,216.1
Accumulated depreciation		(2,161.0	)		(2,014.8	)

		3,665.0			3,201.3
Other property		7.9			8.2

Total property, plant and equipment		3,672.9			3,209.5

Current Assets
Cash and cash equivalents		6.9			15.4
Receivables, less allowance for uncollectibles of $1.1 million and $1.6 million at Dec. 31, 2002 and 2001, respectively		186.5			166.8
Inventories
Fuel, at average cost		79.1			69.0
Materials and supplies		48.1			51.0
Prepayments and other		18.4			12.5

Total current assets		339.0			314.7

Deferred Debits
Unamortized debt expense		23.7			8.0
Deferred income taxes		133.3			136.2
Regulatory assets		163.2			198.3
Other		5.6			12.5

Total deferred debits		325.8			355.0

Total Assets	$	4,337.7		$	3,879.2

The accompanying notes are an integral part of the consolidated financial statements.

106

TAMPA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

Liabilities and Capital (millions) Dec. 31,	2002		2001
Capital
Common stock	$	1,535.1	$	1,318.1
Retained earnings		302.9		304.4
Accumulated other comprehensive loss		—		(0.1	)

Total capital		1,838.0		1,622.4
Long-term debt, less amount due within one year		1,345.6		880.9

Total capitalization		3,183.6		2,503.3

Current Liabilities
Long-term debt due within one year		81.0		156.1
Notes payable		10.5		249.0
Accounts payable		178.8		135.8
Customer deposits		94.6		86.3
Interest accrued		18.3		16.1
Taxes accrued		46.9		57.3

Total current liabilities		430.1		700.6

Deferred Credits
Deferred income taxes		483.1		441.6
Investment tax credits		27.1		31.6
Regulatory liabilities		98.1		106.2
Other		115.7		95.9

Total deferred credits		724.0		675.3

Total liabilities and capital	$	4,337.7	$	3,879.2

The accompanying notes are an integral part of the consolidated financial statements.

107

TAMPA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(millions) Year Ended Dec. 31,	2002			2001			2000
Revenues
Electric (includes franchise fees and gross receipts taxes of $63.5 million in 2002, $56.0 million in 2001, and $47.5 million in 2000)	$	1,582.5		$	1,411.8		$	1,352.9
Gas (includes franchise fees and gross receipts taxes of $10.3 million in 2002, $15.1 million in 2001, and $12.2 million in 2000)		318.1			352.9			314.5

Total revenues		1,900.6			1,764.7			1,667.4

Expenses
Operation
Fuel		424.1			346.5			323.3
Purchased power		253.7			209.7			192.1
Cost of natural gas sold		148.9			186.4			157.0
Other		273.0			249.1			246.3
Maintenance		112.0			103.2			99.9
Depreciation		220.1			201.3			187.4
Taxes, federal and state income		100.3			97.7			95.8
Taxes, other than income		132.6			129.3			120.8

Total expenses		1,664.7			1,523.2			1,422.6

Income from operations		235.9			241.5			244.8

Other income
Allowance for other funds used during construction		24.9			6.6			1.6
Other income, net		1.5			4.1			—

Total other income		26.4			10.7			1.6

Interest charges
Interest on long-term debt		77.5			62.5			52.4
Other interest		(1.6	)		15.2			28.4
Allowance for borrowed funds used during construction		(9.6	)		(2.6	)		(0.7	)

Total interest charges		66.3			75.1			80.1

Net income	$	196.0		$	177.1		$	166.3

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(millions) Year Ended Dec. 31,	2002		2001			2000
Net income	$	196.0	$	177.1		$	166.3

Other comprehensive (loss) income, net of tax
Net unrealized losses on cash flow hedges		0.1		(0.1	)		—

Other comprehensive (loss) income, net of tax		0.1		(0.1	)		—

Comprehensive income	$	196.1	$	177.0		$	166.3

The accompanying notes are an integral part of the consolidated financial statements.

108

TAMPA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(millions) Year Ended Dec. 31,	2002			2001			2000
Cash flows from operating activities
Net income	$	196.0		$	177.1		$	166.3
Adjustments to reconcile net income to net cash from operating activities:
Depreciation		220.1			201.3			187.4
Deferred income taxes		23.7			(1.9	)		(39.4	)
Investment tax credits, net		(4.4	)		(4.5	)		(4.4	)
Allowance for funds used during construction		(34.5	)		(9.2	)		(2.3	)
Deferred recovery clause		72.2			(19.0	)		(68.7	)
Refund to customers		(6.4	)		—			(13.2	)
Receivables, less allowance for uncollectibles		(19.8	)		24.1			(33.3	)
Inventories		(7.2	)		(10.8	)		13.0
Taxes accrued		(10.4	)		(14.3	)		40.7
Interest accrued		2.3			(18.1	)		21.3
Accounts payable		43.1			(52.4	)		24.3
Other		—			20.9			45.7

Cash flows from operating activities		474.7			293.2			337.4

Cash flows from investing activities
Capital expenditures		(685.7	)		(499.3	)		(349.3	)
Allowance for funds used during construction		34.5			9.2			2.3

Cash flows from investing activities		(651.2	)		(490.1	)		(347.0	)

Cash flows from financing activities
Proceeds from contributed capital from parent		217.0			170.0			105.0
Proceeds from long-term debt		689.3			250.0			154.5
Repayment of long-term debt		(302.4	)		(54.4	)		(84.1	)
Net increase (decrease) in short-term debt		(238.5	)		17.8			(40.0	)
Payment of dividends		(197.4	)		(171.8	)		(151.2	)

Cash flows from financing activities		168.0			211.6			(15.8	)

Net (decrease) increase in cash and cash equivalents		(8.5	)		14.7			(25.4	)
Cash and cash equivalents at beginning of year		15.4			0.7			26.1

Cash and cash equivalents at end of year	$	6.9		$	15.4		$	0.7

Supplemental Disclosure of Cash Flow Information
Cash paid during the year for:
Interest	$	74.0		$	85.3		$	66.7
Income taxes	$	143.9		$	119.9		$	98.4

The accompanying notes are an integral part of the consolidated financial statements.

109

TAMPA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

(millions) Year Ended Dec. 31,	2002		2001		2000
Balance, Beginning of Year	$	304.3	$	299.0	$	283.9
Add-Net income		196.0		177.1		166.3

		500.3		476.1		450.2

Deduct-Cash dividends on capital stock
Common		197.4		171.8		151.2

		197.4		171.8		151.2

Balance, End of Year	$	302.9	$	304.3	$	299.0

CONSOLIDATED STATEMENTS OF CAPITALIZATION

Capital Stock Outstanding
Dec. 31,

Cash dividends
paid (1)

(millions, except share amounts)

Current Redemption Price

Shares

Amount

Per Share

Amount

Common stock-Without par value

25 million shares authorized

2002

N/A

1,535.1

N/A

197.4

2001

N/A

1,318.1

171.8

Preferred Stock-$100 Par Value

1.5 million shares authorized, none outstanding.

Preferred Stock—no Par

2.5 million shares authorized, none outstanding.

Preference Stock—no Par

2.5 million shares authorized, none outstanding.

(1)

Quarterly dividends paid on Feb. 15, May 15, Aug. 15 and Nov. 15.

The accompanying notes are an integral part of the consolidated financial statements.

110

TAMPA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)

(millions) Long-Term Debt Outstanding at Dec. 31,	Due	2002			2001
Tampa Electric
First mortgage bonds (issuable in series):
7.75% (effective rate of 7.96%)	2022	$	75.0		$	75.0
6.125% (effective rate of 6.61%)	2003		75.0			75.0
Installment contracts payable (3):
5.75%	2002		—			22.5
7.875% Refunding bonds (4)	2002		—			25.0
8% Refunding bonds (4)	2002		—			100.0
6.25% Refunding bonds (effective rate of 6.81%) (5)	2034		86.0			86.0
5.85% (effective rate of 5.88%)	2030		75.0			75.0
5.1% Refunding bonds (effective rate of 5.78%) (6)	2013		60.7			—
5.5% Refunding bonds (effective rate of 6.35%) (6)	2023		86.4			—
4% for 2002 (effective rate of 4.21%) and variable rate of 1.45% for 2001 (1) (7)	2025		51.6			51.6
4% for 2002 (effective rate of 4.16%) and variable rate of 1.47% for 2001 (1) (7)	2018		54.2			54.2
4.25% for 2002 (effective rate of 4.43%) and variable rate of 1.52% for 2001 (1) (7)	2020		20.0			20.0
Notes: 5.86% (1)	2002		—			100.0
Notes: 6.875% (effective rate of 6.98%) (2)	2012		210.0			210.0
Notes: 6.375% (effective rate of 7.34%) (2)	2012		330.0			—
Notes: 5.375% (effective rate of 5.58%) (2)	2007		125.0			—

			1,248.9			894.3

Peoples Gas System
Senior Notes (8)
10.35%	2007		4.2			5.0
10.33%	2008		5.6			6.4
10.3%	2009		7.2			7.8
9.93%	2010		7.4			8.0
8.0%	2012		25.4			27.5
Notes: 5.86% (1)	2002		—			50.0
Notes: 6.875% (effective rate of 6.98%) (2)	2012		40.0			40.0
Notes: 6.375% (effective rate of 7.34%) (2)	2012		70.0			—
Notes: 5.375% (effective rate of 5.58%) (2)	2007		25.0			—

			184.8			144.7

			1,433.7			1,039.0
Unamortized debt premium (discount), net			(7.1	)		(2.0	)

			1,426.6			1,037.0
Less amount due within one year (9)			81.0			156.1

Total long-term debt		$	1,345.6		$	880.9

111

(1)

Composite year-end interest rate.

(2)

These notes are subject to redemption in whole or in part, at any time, at the option of the company.

(3)

Tax exempt securities.

(4)

Proceeds of these bonds were used to refund bonds with interest rates of 11.625%—12.625%. For accounting purposes, interest expense has been recorded using blended rates of 8.28%—8.66% on the original and refunding bonds, consistent with regulatory treatment.

(5)

(6)

Proceeds on these bonds were used to refund bonds with interest rates of 5.75%—8%.

(7)

The interest rate on these bonds was fixed for a five-year term on Aug. 5, 2002.

(8)

These long-term debt agreements contain various restrictive covenants, including provisions related to interest coverage, maximum levels of debt to total capitalization and limitations on dividends.

(9)

Of the amount due in 2003, $0.8 million may be satisfied by the substitution of property in lieu of cash payments.

Substantially all of the property, plant and equipment of the company is pledged as collateral to secure its first mortgage bonds and certain pollution control equipment is pledged to secure installment contracts payable. Maturities and annual sinking fund requirements of long-term debt for the years 2004, 2005, 2006 and 2007 are $5.3 million, $5.5 million, $5.9 million and $156.1 million, respectively. Of these amounts $0.8 million per year for 2003 through 2006 may be satisfied by the substitution of property in lieu of cash payments.

At Dec. 31, 2002, total long-term debt had a carrying amount of $1,352.6 million and an estimated fair market value of $1,440.8 million. The estimated fair market value of long-term debt was based on quoted market prices for the same or similar issues, on the current rates offered for debt of the same remaining maturities, or for long-term debt issues with variable rates that approximate market rates, at carrying amounts. The carrying amount of long-term debt due within one year approximated fair market value because of the short maturity of these instruments.

The accompanying notes are an integral part of the consolidated financial statements.

112

TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A. Summary of Significant Accounting Policies

The significant accounting policies are as follows:

Principles of Consolidation

Tampa Electric Company (the “company”) is a wholly-owned subsidiary of TECO Energy, Inc. The company is comprised of the Electric division, generally referred to as Tampa Electric, and the Natural Gas division, generally referred to as Peoples Gas System (PGS).

All significant intercompany balances and intercompany transactions have been eliminated in consolidation.

The use of estimates is inherent in the preparation of financial statements in accordance with generally accepted accounting principles.

Deferred Credits and Other Liabilities

Other deferred credits primarily include the accrued post-retirement benefit liability and pension liability.

Revenue Recognition

Tampa Electric Company recognizes revenues in accordance with the Securities and Exchange Commission’s Staff Accounting Bulletin (SAB) 101, Revenue Recognition in Financial Statements. The criteria outlined in SAB 101 are that a) there is persuasive evidence that an arrangement exists; b) delivery has occurred or services have been rendered; c) the fee is fixed and determinable; and d) collectibility is reasonably assured. Except as discussed below, the company recognizes revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer.

The regulated utilities’ (Tampa Electric and Peoples Gas System) retail businesses and the prices charged to customers are regulated by the Florida Public Service Commission (FPSC). Tampa Electric’s wholesale business is regulated by the Federal Energy Regulatory Commission (FERC). As a result, the regulated utilities qualify for the application of Financial Accounting Standard No. (FAS) 71, Accounting for the Effects of Certain Types of Regulation. See Note D for a discussion of the applicability of FAS 71 to the company.

Revenues and Fuel Costs

Revenues include amounts resulting from cost recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline capacity and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over-recovery or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as deferred credits, and under-recoveries of costs are recorded as deferred charges.

In 1994, Tampa Electric bought out a long-term coal supply contract which would have expired in 2004 for a lump sum payment of $25.5 million. In February 1995, the FPSC authorized the recovery of this buy-out amount plus carrying costs through the Fuel and Purchased Power Cost Recovery Clause over the 10-year period beginning April 1, 1995. In each of the years 2002, 2001 and 2000, $2.7 million of buy-out costs were amortized to expense.

The regulated utilities accrue base revenues for services rendered but unbilled to provide a closer matching of revenues and expenses.

Tampa Electric’s objectives of stabilizing prices from 1996 through 1999 and securing fair earnings opportunities during this period were accomplished through a series of agreements entered into in 1996 with Florida’s Office of Public Counsel (OPC) and the Florida Industrial Power Users Group which were approved by the FPSC. Prior to these agreements, the FPSC approved a plan submitted by Tampa Electric to defer certain 1995 revenues.

In general, under these agreements Tampa Electric was allowed to defer revenues in 1995 and 1996 during the construction of Polk Unit 1 and recognize these revenues in 1997 and 1998 after commercial operation of the unit. Other components of the agreements were a base rate freeze through 1999 and refunds to customers totaling $50 million during the period October 1996 through December 1998 while Tampa Electric was allowed recovery of the capital costs incurred for the Polk Unit 1 project.

113

million was to be refunded to customers. In February 2001, OPC protested the FPSC’s decision. The FPSC held hearings on the issue in August 2001 and upheld its original decision. In January 2002, the OPC filed a motion with the FPSC asking for reconsideration of its decision, alleging the FPSC relied on erroneous information. This was not granted and Tampa Electric made refunds associated with 1999 earnings in 2002. Over the terms of the agreements, the company refunded in total about $69 million.

Purchased Power

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. For the years ended Dec. 31, 2002, 2001 and 2000, Tampa Electric purchased power of $253.7 million, $209.7 million and $192.1 million, respectively. These purchased power costs are recoverable through an FPSC-approved cost recovery clause.

Planned Major Maintenance

Depreciation

Tampa Electric Company provides for depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage, of depreciable property over its estimated service life. The provision for utility plant in service, expressed as a percentage of the original cost of depreciable property, was 4.2% for 2002 and 2001, and 4.1% for 2000.

The original cost of utility plant retired or otherwise disposed of and the cost of removal less salvage are charged to accumulated depreciation. The implementation of FAS 143, Accounting for Asset Retirement Obligations in 2003 will result in the carrying amount of long-lived assets being increased, and this adjusted capitalized amount depreciated over the useful life of the asset. (See Note N—Accounting for Asset Retirement Obligations.)

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

Tampa Electric Company is allowed to recover certain costs incurred from customers through prices approved by the regulatory process. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Statement of Income. These amounts totaled $73.8 million, $71.1 million and $59.7 million, respectively, for 2002, 2001 and 2000. Franchise fees and gross receipt taxes payable by the company are included as an expense on the Consolidated Statement of Income in Taxes, other than income. For 2002, 2001 and 2000 these totaled $73.7 million, $71.0 million and $59.8 million, respectively.

Allowance for Funds Used During Construction (AFUDC)

AFUDC is a non-cash credit to income with a corresponding charge to utility plant, which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. The rate was 7.79% for 2002, 2001, and 2000. Total AFUDC for 2002, 2001 and 2000 was $34.5 million, $9.2 million and $2.3 million, respectively. The base on which AFUDC is calculated excludes construction work in progress, which has been included in rate base.

Deferred Income Taxes

The company utilizes the liability method in the measurement of deferred income taxes. Under the liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at current tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates.

114

Investment Tax Credits

Investment tax credits have been recorded as deferred credits and are being amortized to income tax expense over the service lives of the related property.

Asset Impairments

Effective Jan. 1, 2002, Tampa Electric Company adopted FAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which supersedes FAS 121, Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of. FAS 144 addresses accounting and reporting for the impairment or disposal of long-lived assets, including the disposal of a segment of a business.

Restrictions on Dividend Payments and Transfer of Assets

Tampa Electric’s first mortgage bonds and certain of PGS’ long-term debt issues contain provisions that limit the dividend payment on Tampa Electric Company’s common stock. At Dec. 31, 2002, substantially all of the company’s retained earnings were available for dividends on its common stock.

Lease Accounting Amendment

Reclassifications

Certain prior year amounts were reclassified to conform with current year presentation.

B. Derivatives and Hedging

From time to time, Tampa Electric Company enters into futures, forwards, swaps and option contracts to limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations at Tampa Electric and PGS.

The company uses derivatives only to reduce normal operating and market risks, not for speculative purposes. The company’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.

The risk management policies adopted by the company provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group which is independent of all operating companies.

At Dec. 31, 2002, the company had derivative assets totaling $3.4 million. At Dec. 31, 2001, the company had derivative liabilities totaling $0.1 million. At Dec. 31, 2001, accumulated OCI included $0.1 million of unrealized after-tax losses, representing the fair value of cash flow hedges whose transactions will occur in the future. There were no amounts recorded in OCI as of Dec. 31, 2002. Amounts recorded in OCI reflect the value of derivative instruments designated as hedges, based on market prices as of the balance sheet date. These amounts are expected to fluctuate with movements in market prices and may or may not be realized as a loss upon future reclassification from OCI.

115

As of Dec. 31, 2002, the company had transactions in place to hedge commodity price that qualify for cash flow hedge accounting treatment under FAS 133. During 2002, the company reclassified net pretax gains of $0.2 million to earnings for cash flow hedges, compared to pretax losses of $0.7 million in 2001. Amounts reclassified from OCI were primarily related to cash flow hedges of physical purchases of natural gas. For these types of hedge relationships, the loss on the derivative, reclassified from OCI to earnings, is offset by the reduced expense arising from lower prices paid for spot purchases of natural gas. Conversely, reclassification of a gain from OCI to earnings is offset by the increased cost of spot purchases of natural gas.

Based on the fair values at Dec. 31, 2002, pretax gains of $3.4 million are expected to be reversed from OCI to the Consolidated Statement of Income within the next twelve months. However, these gains and other future reclassifications from OCI will fluctuate with movements in the underlying market price of the derivative instruments. The company does not currently have any cash flow hedges for transactions forecasted to take place in periods subsequent to 2003.

C. Goodwill and Other Intangible Assets

Effective Jan. 1, 2002, Tampa Electric Company adopted FAS 141, Business Combinations, and FAS 142, Goodwill and Other Intangible Assets. FAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting. With the adoption of FAS 142, goodwill is no longer subject to amortization. Rather, goodwill is subject to an annual assessment for impairment by applying a fair-value-based test. Under the new rules, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented, or exchanged, regardless of the acquiror’s intent to do so. These intangible assets are required to be amortized over their useful lives. The company has no recorded goodwill.

D. Regulatory Assets and Liabilities

116

Regulatory Assets and Liabilities

(millions) Dec. 31,	2002		2001
Regulatory assets:
Regulatory tax asset (1)	$	54.9	$	41.3
Other:
Cost recovery clauses		34.7		105.2
Coal contract buy-out (2)		5.4		8.1
Unamortized refinancing costs (3)		35.9		13.7
Environmental remediation		20.3		22.3
Competitive rate adjustment		7.4		5.9
Other		4.6		1.8

		108.3		157.0

Total regulatory assets	$	163.2	$	198.3

Regulatory liabilities:
Regulatory tax liability (1)	$	36.6	$	43.1
Other:
Deferred allowance auction credits		2.1		1.1
Cost recovery clauses		2.2		0.5
Revenue refund		—		6.3
Environmental remediation		20.3		22.3
Transmission and distribution storm reserve		36.0		32.0
Deferred gain on property sales(4)		0.9		0.9

		61.5		63.1

Total regulatory liabilities	$	98.1	$	106.2

(1)

Related primarily to plant life. Includes excess deferred taxes of $20.9 million and $24.6 million as of Dec. 31, 2002 and 2001, respectively.

(2)

Amortized over a 10-year period ending December 2004.

(3)

Unamortized refinancing costs:

Related to debt transactions as follows (millions):		Amortized until:
$155.0		2003
$ 51.6		2005
$ 22.1		2007
$ 25.0		2011
$ 50.0		2011
$150.0		2012
$150.0		2012
$ 85.9		2014
$ 25.0		2021
$100.0		2022

(4)

Amortized over a 5-year period with various ending dates.

E. Short-term Debt

Notes payable consisted primarily of commercial paper with weighted average interest rates of 1.86% and 1.99% at Dec. 31, 2002 and 2001, respectively. The carrying amount of notes payable approximated fair market value because of the short maturity of these instruments. Tampa Electric has a bank credit facility of $300 million with a maturity date of November 2003. None of the credit facility was drawn at Dec. 31, 2002. The credit facility requires commitment fees of 15 basis points and drawn amounts are charged interest at LIBOR plus 87–97.5 basis points at current ratings.

117

F. Common Stock

Tampa Electric Company is a wholly owned subsidiary of TECO Energy, Inc.

	Common Stock			Issue Expense			Total
(millions, except per share amounts)	Shares	Amount		Issue Expense			Total
Balance Dec. 31, 1999	10	$	1,043.8	$	(0.7	)	$	1,043.1
Contributed capital from parent	—		105.0		—			105.0

Balance Dec. 31, 2000	10		1,148.8		(0.7	)		1,148.1
Contributed capital from parent	—		170.0		—			170.0

Balance Dec. 31, 2001	10		1,318.8		(0.7	)		1,318.1
Contributed capital from parent	—		217.0		—			217.0

Balance Dec. 31, 2002	10	$	1,535.8	$	(0.7	)	$	1,535.1

G. Comprehensive Income

FAS 130, Reporting Comprehensive Income, requires that comprehensive income, which includes net income as well as certain changes in assets and liabilities recorded in common equity, be reported in the financial statements. Tampa Electric Company reported the following comprehensive income (loss) in 2002 and 2001 related to changes in the fair value of cash flow hedges. There was no comprehensive income (loss) for 2000.

Comprehensive Income (loss)

(millions)	Gross			Tax			Net
2002
Unrealized (loss) gain on cash flow hedges	$	0.3		$	0.1		$	0.2
Less: Loss (gain) reclassified to net income		(0.2	)		(0.1	)		(0.1	)

Total other comprehensive income (loss)	$	0.1		$	—		$	0.1

2001
Unrealized (loss) gain on cash flow hedges	$	(0.8	)	$	(0.3	)	$	(0.5	)
Less: Loss (gain) reclassified to net income		0.7			0.3			0.4

Total other comprehensive income (loss)	$	(0.1	)	$	—		$	(0.1	)

H. Employee Postretirement Benefits

Pension Benefits

Tampa Electric Company is a participant in the comprehensive retirement plans of TECO Energy, including a non-contributory defined benefit retirement plan which covers substantially all employees. On April 1, 2000, the plan was amended to provide for benefits to be earned and payable substantially on a lump sum basis through an age and service credit schedule for eligible participants leaving the company on or after July 1, 2001. Other significant provisions of the plan, such as eligibility, definitions of credited service, final average earnings, etc., were largely unchanged. This amendment resulted in decreased pension expense at TECO Energy of approximately $0.8 million and $2.0 million in 2001 and 2000, respectively, and a reduction of benefit obligation of $6.2 million and $14.4 million at Sept. 30, 2001 and 2000, respectively.

TECO Energy’s policy is to fund the plan within the guidelines set by ERISA for the minimum annual contribution and the maximum allowable as a tax deduction by the IRS. About 53 percent of plan assets were invested in common stocks and 47 percent in fixed income investments at Sept. 30, 2002.

Amounts shown also include the unfunded obligations for the supplemental executive retirement plan, non-qualified, non-contributory defined benefit retirement plans available to certain senior management. TECO Energy reported other comprehensive loss of $4.4 million in 2002 and other comprehensive income of $0.3 million and $2.0 million in 2001 and 2000, respectively, related to adjustments to the minimum pension liability associated with the supplemental executive retirement plan.

In 2001, TECO Energy elected to change the measurement date for pension obligations and plan assets from Dec. 31 to Sept. 30. The effect of this accounting change is not material.

Components of net pension expense, reconciliation of the funded status and the accrued pension liability are presented below for TECO Energy consolidated.

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Components of net periodic pension benefit expense

(millions)	2002			2001			2000
Service cost (benefits earned during the period)	$	11.8		$	11.2		$	10.7
Interest cost on projected benefit obligations		28.7			27.9			27.5
Expected return on assets		(42.9	)		(42.0	)		(40.8	)
Amortization of:
Transition obligation (asset)		(1.1	)		(1.1	)		(1.0	)
Prior service cost (benefit)		(0.5	)		(0.5	)		0.2
Actuarial (gain) loss		(3.7	)		(4.4	)		(5.6	)

Pension expense (benefit)		(7.7	)		(8.9	)		(9.0	)
Special termination benefit charge		2.7			—			1.1
Additional amounts recognized		—			—			—

Net pension expense (benefit) recognized in the
Consolidated Statements of Income (1)	$	(5.0	)	$	(8.9	)	$	(7.9	)

(1)

Tampa Electric Company’s portion was ($7.8) million, ($10.4) million and ($9.4) million for 2002, 2001 and 2000, respectively.

Reconciliation of the funded status of the retirement plan and the accrued pension prepayment/(liability)

(millions)	2002			2001
Change in benefit obligation
Net benefit obligation at prior measurement date	$	382.3		$	379.9
Service cost		11.8			11.2
Interest cost		28.7			27.9
Actuarial (gain) loss		58.3			(8.7	)
Plan amendments		1.1			(6.2	)
Special termination benefits		2.7			—
Gross benefits paid		(29.8	)		(21.8	)

Net benefit obligation at measurement date	$	455.1		$	382.3

Change in plan assets
Fair value of plan assets at prior measurement date	$	428.0		$	493.8
Actual return on plan assets		(24.9	)		(43.7	)
Employer contributions		1.7			2.1
Gross benefits paid (including expenses)		(32.9	)		(24.2	)

Fair value of plan assets at measurement date	$	371.9		$	428.0

Funded status
Funded status at measurement date	$	(83.2	)	$	45.7
Net contributions after measurement date		0.4			0.4
Unrecognized net actuarial (gain) loss		88.9			(44.0	)
Unrecognized prior service cost (benefit)		(7.4	)		(9.0	)
Unrecognized net transition obligation (asset)		(2.5	)		(3.6	)

Accrued liability at end of year	$	(3.8	)	$	(10.5	)

Amounts recognized in the statement of financial position
Prepaid benefit cost	$	14.7		$	6.3
Accrued benefit cost		(18.5	)		(16.8	)
Additional minimum liability		(13.8	)		(6.2	)
Intangible asset		1.5			1.1
Accumulated other comprehensive income		12.3			5.1

Net amount recognized at end of year	$	(3.8	)	$	(10.5	)

Assumptions used in determining actuarial valuations
Discount rate to determine projected benefit obligation		6.75	%		7.5	%
Rate of increase in compensation levels		4.8	%		4.7	%
Plan asset growth rate through time		9.0	%		9.0	%

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Other Postretirement Benefits

Tampa Electric provides certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 meeting certain service requirements. The company contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and June 30, 2001, is limited to a defined dollar benefit based on years of service. On April 1, 2000, the company adopted changes to this program for participants retiring from the company on or after July 1, 2001. The company contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after July 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. The impact of this amendment, including a change in the company’s commitment for future retirees combined with a grandfathering provision for current retired participants, resulted in a reduction in the benefit obligation of $1.4 million in 2001. Postretirement benefit levels are substantially unrelated to salary. The company reserves the right to terminate or modify the plans in whole or in part at any time.

In 2001, the company elected to change the measurement date for benefit obligations from Dec. 31 to Sept. 30. The effect of this accounting change was not material.

Components of postretirement benefit cost

(millions)	2002			2001		2000
Service cost (benefits earned during the period)	$	2.4		$	2.3	$	2.0
Interest cost on projected benefit obligations		8.6			8.4		7.0
Amortization of:
Transition obligation (straight line over 20 years)		2.1			2.1		2.1
Prior service cost		1.7			1.7		1.5
Actuarial loss/(gain)		0.1			0.3		(0.2	)

Pension expense		14.9			14.8		12.4
Special termination benefits		0.6			—		0.2
Additional amounts recognized		(0.1	)		—		(0.2	)

Net periodic postretirement benefit expense	$	15.4		$	14.8	$	12.4

Reconciliation of the funded status of the postretirement benefit plan and the accrued liability

(millions)	2002			2001
Change in benefit obligation
Net benefit obligation at prior measurement date	$	114.8		$	103.9
Service cost		2.4			2.3
Interest cost		8.6			8.4
Plan participants’ contributions		0.8			0.7
Actuarial loss		17.3			5.8
Plan amendments		—			(1.4	)
Special termination benefits		0.6			—
Gross benefits paid		(5.7	)		(4.9	)

Net benefit obligation at measurement date	$	138.8		$	114.8

Change in plan assets
Fair value of plan assets at prior measurement date		—			—
Employer contributions		4.9			4.2
Plan participants= contributions		0.8			0.7
Gross benefits paid (including expenses)		(5.7	)		(4.9	)

Fair value of plan assets at measurement date	$	—		$	—

Funded status
Funded status at measurement date	$	(138.8	)	$	(114.8	)
Net contributions after measurement date		1.5			1.2
Unrecognized net actuarial loss		29.5			12.2
Unrecognized prior service cost		20.3			22.0
Unrecognized net transition obligation		21.1			23.2

Accrued liability at end of year	$	(66.4	)	$	(56.2	)

Assumptions Used in Determining Actuarial Valuations
Discount rate to determine projected benefit obligation		6.75	%		7.5	%

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The assumed health care cost trend rate for medical costs was 12.5% in 2002 and decreases to 5.0% in 2013 and thereafter.

A 100 basis point increase in the medical trend rates would produce a 7 percent ($0.8 million) increase in the aggregate service and interest cost for 2002, and a 5 percent ($7.2 million) increase in the accumulated postretirement benefit obligation as of Sept. 30, 2002.

A 100 basis point decrease in the medical trend rates would produce a 3 percent ($0.4 million) decrease in the aggregate service and interest cost for 2001 and a 3 percent ($3.8 million) decrease in the accumulated postretirement benefit obligation as of Sept. 30, 2001.

I. Income Tax Expense

Tampa Electric Company is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. Tampa Electric Company’s income tax expense is based upon a separate return computation. Income tax expense consists of the following:

Income Tax Expense

(millions)	Federal			State			Total
2002
Currently payable	$	66.7		$	14.9		$	81.6
Deferred		23.2			0.4			23.6
Amortization of investment tax credits		(4.4	)		—			(4.4	)

Total income tax expense	$	85.5		$	15.3			100.8

Included in other income, net								0.5

Included in operating expenses							$	100.3

2001
Currently payable	$	88.6		$	15.7		$	104.3
Deferred		(1.3	)		(0.7	)		(2.0	)
Amortization of investment tax credits		(4.4	)		—			(4.4	)

Total income tax expense	$	82.9		$	15.0			97.9
Included in other income, net								0.2

Included in operating expenses							$	97.7

2000
Currently payable	$	128.3		$	11.4		$	139.7
Deferred		(42.5	)		3.1			(39.4	)
Amortization of investment tax credits		(4.4	)		—			(4.4	)

Total income tax expense	$	81.4		$	14.5			95.9
Included in other income, net								0.1

Included in operating expenses							$	95.8

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Deferred Income Tax Assets and Liabilities

(millions) Dec. 31,	2002			2001
Deferred tax assets (1)
Property related	$	90.3		$	106.1
Leases		3.5			3.9
Insurance reserves		17.7			16.5
Early capacity payments		6.0			6.5
Other		—			3.2

Total deferred income tax assets		117.5			136.2

Deferred income tax liabilities (1)
Property related		(499.5	)		(461.2	)
Other		32.2			19.6

Total deferred income tax liabilities		(467.3	)		(441.6	)

Accumulated deferred income taxes	$	(349.8	)	$	(305.4	)

(1)

Certain property related assets and liabilities have been netted.

The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons:

Effective Income Tax Rate

(millions)	2002			2001			2000
Net income	$	196.0		$	177.1		$	166.3
Total income tax provision		100.8			97.9			95.9

Income before income taxes	$	296.8		$	275.0		$	262.2

Income taxes on above at federal statutory rate of 35%	$	103.8		$	96.2		$	91.7
Increase (decrease) due to
State income tax, net of federal income tax		10.0			9.8			9.5
Amortization of investment tax credits		(4.4	)		(4.5	)		(4.4	)
Equity portion of AFUDC		(8.7	)		(2.3	)		(0.5	)
Other		0.1			(1.3	)		(0.4	)

Total income tax provision	$	100.8		$	97.9		$	95.9

Provision for income taxes as a percent of income before income taxes		34.0	%		35.6	%		36.6	%

J. Related Party Transactions

Tampa Electric and TECO-Panda Generating Company (TPGC) II, an affiliate of TECO Power Services, Inc., entered into an assignment and assumption agreement whereby Tampa Electric obtained TPGC II’s rights and interests to four combustion turbines being purchased from General Electric, and assumed the corresponding liabilities and obligations for such equipment. In accordance with the terms of the assignment and assumption agreement, Tampa Electric paid $62.5 million to TPGC II as reimbursement for amounts already paid to General Electric by TPGC II for such equipment.

A summary of activities between Tampa Electric Company and its affiliates follows:

Net transactions with affiliates:

(millions)	2002		2001		2000
Fuel and interchange related, net	$	144.9	$	162.0	$	155.7
Administrative and general, net	$	10.7	$	22.1	$	24.7

Amounts due from or to affiliates of the company at Dec. 31,

(millions)	2002		2001
Accounts receivable (1)	$	6.6	$	7.5
Accounts payable (1)	$	23.6	$	13.0

(1)

Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.

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K. Segment Information

Tampa Electric Company is a public utility operating within the state of Florida. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to almost 598,000 customers in West Central Florida. Its Peoples Gas System division is engaged in the purchase, distribution and marketing of natural gas for more than 281,000 residential, commercial, industrial and electric power generation customers in the state of Florida.

Segment Information

(millions)	Revenues			Net Income		Depreciation		Assets at Dec. 31,			Capital Expenditures
2002
Tampa Electric	$	1,583.2	(1)	$	171.8	$	189.8	$	3,745.8		$	632.2
Peoples Gas System		318.1			24.2		30.5		592.0	(2)		53.5
Other and eliminations		(0.7	)		—		—		—			—

Tampa Electric Company	$	1,900.6		$	196.0	$	220.3	$	4,337.8		$	685.7

2001
Tampa Electric	$	1,412.7	(1)	$	154.0	$	173.4	$	3,328.0		$	426.3
Peoples Gas System		352.9			23.1		27.9		551.2	(2)		73.0
Other and eliminations		(0.9	)		—		—		—			—

Tampa Electric Company	$	1,764.7		$	177.1	$	201.3	$	3,879.2		$	499.3

2000
Tampa Electric	$	1,353.8	(1)	$	144.5	$	161.6	$	3,014.2		$	267.1
Peoples Gas System		314.5			21.8		25.8		535.6	(2)		82.2
Other and eliminations		(0.9	)		—		—		—			—

Tampa Electric Company	$	1,667.4		$	166.3	$	187.4	$	3,549.8		$	349.3

(1)

Revenues from sales to affiliates were $34.4 million, $32.6 million and $32.4 million in 2002, 2001 and 2000, respectively.

(2)

Includes a regulatory asset for estimated environmental remediation of $20.3 million at Dec. 31, in 2002 and $22.3 million at Dec. 31, 2001 and 2000.

L. Commitments and Contingencies

Capital Investments

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company 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 Dec. 31, 2002, Tampa Electric Company has estimated its ultimate financial liability to be $20 million, and this amount has been accrued in the company’s financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, 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.

123

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

Guarantees and Letters of Credit

Tampa Electric Company has outstanding letters of credit of $0.9 million at Dec. 31, 2002, which guarantee performance to third parties related to debt service.

In addition, Tampa Electric Company includes indemnity clauses, in the normal course of business, in certain agreements with vendors and other third parties. Such clauses may provide indemnification to the counter-party for certain amounts such as legal fees, environmental remediation costs and other similar costs arising from potential future events or changes in laws or regulations. As these agreements cover a variety of goods and services, and have varying triggering events dependent on actions by third parties, Tampa Electric Company is unable to estimate the maximum potential future exposure under these clauses. As claims are made or changes in laws or regulations indicate, an amount related to the indemnification is reflected in the financial statements.

Financial Covenants

A summary of Tampa Electric’s significant financial covenants is as follows:

Tampa Electric Significant Financial Covenants

(millions) Instrument	Financial Covenant(1)	Requirement/ Restriction	Calculation at Dec. 31, 2002
Tampa Electric
Mortgage bond indenture	Dividend restriction	Cumulative distributions cannot exceed cumulative net income plus $4	$189 unrestricted
PGS senior notes	EBIT/interest	Minimum of 2.0 times	3.7 times
	Restricted payments	Shareholder equity at least $500	$1,838
	Funded debt/capital	Cannot exceed 65%	44.8%
	Sale of assets	Less than 20% of total assets	0%
Credit facility	Debt/capital	Cannot exceed 60%	43.9%
	EBITDA/interest	Minimum of 2.5 times	7.8 times

(1)

As defined in applicable instrument.

N. New Accounting Pronouncements

Accounting for Asset Retirement Obligations

124

Exit or Disposal Costs

Tampa Electric Company opted to adopt early FAS 146 in 2002. Early retirements were accepted by 52 employees at Tampa Electric’s electric division in mid-2002. Costs associated with this program were approximately $6.3 million and were recognized in operation expenses in the third quarter of 2002. In the fourth quarter of 2002, Tampa Electric Company initiated an additional restructuring program that impacted approximately 130 employees. This program includes retirements, the elimination of positions and other cost control measures. The total costs associated with this program, including severance, salary continuance through the end of 2002 and other benefit costs, were approximately $12 million and were recognized in the fourth quarter of 2002.

Guarantees

In November 2002, the FASB issued Interpretation No. (FIN) 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of others (an interpretation of FAS Nos. 5, 57, and 107 and rescission of FAS Interpretation No. 34), which modifies the accounting and enhances the disclosure of certain types of guarantees. FIN 45 requires that upon issuance of certain guarantees, the guarantor must recognize a liability for the fair value of the obligation it assumes under the guarantee. FIN 45’s provisions for the initial recognition and measurement are to be applied to guarantees issued or modified after Dec. 31, 2002. The disclosure requirements are effective for financial statements of annual periods that end after Dec. 15, 2002 (see Note L).

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

During the period Jan. 1, 2001 to the date of this report, neither TECO Energy nor Tampa Electric Company has had or has filed with the Commission a report as to any changes in or disagreements with accountants on accounting principles or practices, financial statement disclosure, or auditing scope or procedure.

125

PART III

Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

(a)

The information required by Item 10 with respect to the directors of the registrant is included under the caption “Election of Directors” on pages 1 through 3 of TECO Energy’s definitive proxy statement, dated March 7, 2003, for its Annual Meeting of Shareholders to be held on April 22, 2003 (Proxy Statement) and is incorporated herein by reference.

(b)

The information required by Item 10 concerning executive officers of the registrant is included under the caption “Executive Officers of the Registrant” on page 19 of this report.

(c)

The information required by Item 10 concerning Section 16(a) Beneficial Ownership Reporting Compliance is included under that caption on page 18 of the Proxy Statement and is incorporated herein by reference.

(d)

TECO Energy has had a code of ethics applicable to all of its employees and officers for many years. It was expanded to apply to the Board of Directors in 2002. The text of the Standards of Integrity is available on the company’s website at www.tecoenergy.com under Investor Relations. Any amendments to or waivers of the Standards of Integrity for the benefit of any executive officer or director will also be posted on the website.

(e)

Information regarding TECO Energy’s Audit Committee is included on pages 4 and 17 of the Proxy Statement. The Board of Directors has determined that at least one of the independent directors serving on the Audit Committee, Mr. Sherrill Hudson, is an audit committee financial expert, as that term has been defined by the SEC.

Item 11. EXECUTIVE COMPENSATION.

The information required by Item 11 is included in the Proxy Statement beginning on page 6 under the caption “Shareholder Return Performance Graph” and ending on page 13 just above the caption “Shareholder Proposals”, and under the caption “Compensation of Directors” on page 4, and is incorporated herein by reference.

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

The information required by Item 12 is included under the caption “Share Ownership” on pages 5 and 6 of the Proxy Statement and is incorporated herein by reference.

Equity Compensation Plan Information

(thousands, except per share price)	(a)	(b)		(c)
Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans/arrangements approved by the stockholders
1996 Equity Incentive Plan	6,416	$	25.94	4,288
1997 Director Equity Plan	206	$	25.31	270

	6,622	$	25.92	4,558

Equity compensation plans/arrangements not approved by the stockholders
None	—		—	—

Total	6,622	$	25.92	4,558

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Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

The information required by Item 13 is included under the caption “Certain Relationships and Related Transactions” on pages 5 and 6 of the Proxy Statement and is incorporated herein by reference.

Item 14. CONTROLS AND PROCEDURES

TECO Energy, Inc.

(a)

Evaluation of Disclosure Controls and Procedures. TECO Energy’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of TECO Energy’s disclosure controls and procedures (as such term is defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, TECO Energy’s disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to TECO Energy (including its consolidated subsidiaries) required to be included in TECO Energy’s reports filed or submitted under the Exchange Act.

(b)

Changes in Internal Controls. Since the Evaluation Date, there have not been any significant changes in TECO Energy’s internal controls or in other factors that could significantly affect such controls.

Tampa Electric Company

(a)

Evaluation of Disclosure Controls and Procedures. Tampa Electric Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of Tampa Electric’s disclosure controls and procedures (as such term is defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, Tampa Electric’s disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to Tampa Electric (including its consolidated subsidiaries) required to be included in Tampa Electric’s reports filed or submitted under the Exchange Act.

(b)

Changes in Internal Controls. Since the Evaluation Date, there have not been any significant changes in Tampa Electric’s internal controls or in other factors that could significantly affect such controls.

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PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.

(a)

1. TECO Energy, Inc. Financial Statements—See index on page 64

2. Tampa Electric Company Financial Statements—See index on page 104

3. TECO Energy, Inc. Financial Statement Schedules—See index on page 64

4. Tampa Electric Company Financial Statement Schedules—See index on page 104

5. Exhibits—See index beginning on page 139

(b) Reports on Form 8-K

TECO Energy, Inc. filed the following reports on Form 8-K during the last quarter of 2002.

The registrant filed a Current Report on Form 8-K on Oct. 8, 2002 under “Item 5. Other Events” and “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits”, reporting on TECO Energy’s preliminary third quarter results and announcing its plan to conduct a public offering of its common stock.

The registrant filed a Current Report on Form 8-K on Oct. 11, 2002 under “Item 5. Other Events” and “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits”, furnishing certain exhibits for incorporation by reference into the Registration Statement on Form S-3 previously filed with the Securities and Exchange Commission (File No. 333-83958).

The registrant filed a Current Report on Form 8-K on Nov. 5, 2002 under “Item 9. Regulation FD Disclosure”, reporting that the press release for the third quarter earnings, along with additional third quarter financial information, including unaudited financial statements and other financial data, could be found on the registrant’s website.

The registrant filed a Current Report on Form 8-K on Nov. 12, 2002 under “Item 5. Other Events” and “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits”, reporting TECO Energy’s progress on its business plan, credit facilities and bond exchange and responding to investor concerns.

The registrant filed a Current Report on Form 8-K on Nov. 15, 2002 under “Item 5. Other Events”, and “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits”, announcing that TECO Energy agreed to sell a new series of five-year notes to refinance an earlier series of notes.

The registrant filed a Current Report on Form 8-K on Nov. 15, 2002 under “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits”, furnishing the Credit Agreement among Tampa Electric Company, as borrower, Citibank, N.A., as Administrative Agent, Salomon Smith Barney, Inc., as Lead Arranger, Morgan Stanley Senior Funding, Inc., and The Bank of New York, as Co-Syndication Agents, and Bank of America, N.A., as Documentation Agent.

The registrant filed a Current Report on Form 8-K on Nov. 20, 2002 under “Item 5. Other Events”, and “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits”, to furnish certain exhibits including the Purchase Agreement, Eighth Supplemental Indenture, and Registration Rights Agreements for the sales of Notes in private transactions in conformance with Rule 144A under the Securities Act of 1933, as amended.

The registrant filed a Current Report on Form 8-K/A on Nov. 21, 2002 under “Item 5. Other Events”, and “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits”, to furnish, due to a printer error in submitting the Current Report on Nov. 20, 2002, a complete copy of the Purchase Agreement for the sales of notes in private transactions in conformance with Rule 144A under the Securities Act of 1933, as amended.

The registrant filed a Current Report on Form 8-K on Dec. 18, 2002 under “Item 5. Other Events”, and “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits”, reporting that Peoples Gas System had received Florida Public Service Commission authorization to increase the annual gross revenues of the company.

128

10.

The registrant filed a Current Report on form 8-K on Dec. 19, 2002 under “Item 5. Other Events” and “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits”, filing audited historical financial statements for the years ended Dec. 31, 2001, 2002 and 1999 in connection with (1) the adoption of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”, (2) the adoption of the consensus reached through the deliberations of Emerging Issues Task Force No. 02-03, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities” and (3) its announced intent to sell the TECO Coalbed Methane gas assets, requiring its reclassification as discontinued operations.

11.

The registrant filed a Current Report on Form 8-K on Dec. 20, 2002 under “Item 5. Other Events” and “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits”, reporting that TECO Energy, Inc.’s TECO Coalbed Methane subsidiary had completed the sale of substantially all of its assets in Alabama to the Municipal Gas Authority of Georgia.

TECO Energy, Inc. filed the following reports on Form 8-K subsequent to Dec. 31, 2002.

The registrant filed a Current Report on Form 8-K dated Jan. 22, 2003, under “Item 5. Other Events” and “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits”, reporting on TECO Energy’s full-year 2002 financial results.

Tampa Electric Company filed the following report on Form 8-K during the last quarter of 2002.

(c)

The exhibits filed as part of this Form 10-K are listed on the Exhibit Index immediately preceding such Exhibits. The Exhibit Index is incorporated herein by reference.

129

Schedule II

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

For the Years Ended Dec. 31, 2002, 2001 and 2000

(millions)

TECO Energy, Inc.

	Balance at Beginning of Period		Additions							Balance at End of Period
	Balance at Beginning of Period		Charged to Income		Other Charges			Deductions(1)		Balance at End of Period
Allowance for Uncollectible Accounts:
2002	$	7.1	$	9.4	$	0.3		$	10.2	$	6.6
2001	$	8.7	$	8.1	$	(0.3	)	$	9.4	$	7.1
2000	$	3.5	$	10.2	$	0.2		$	5.2	$	8.7

(1)

Write-off of individual bad debt accounts

130

Schedule II

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

For the Years Ended Dec. 31, 2002, 2001 and 2000

(millions)

Tampa Electric Company

	Balance at Beginning of Period		Additions						Balance at End of Period
	Balance at Beginning of Period		Charged to Income		Other Charges		Deductions(1)		Balance at End of Period
Allowance for Uncollectible Accounts:
2002	$	1.6	$	7.7	$	—	$	8.2	$	1.1
2001	$	2.0	$	7.2	$	—	$	7.6	$	1.6
2000	$	1.1	$	5.6	$	—	$	4.7	$	2.0

(1)

Write-off of individual bad debt accounts

131

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 7th day of March, 2003.

TECO ENERGY, INC.

By:		/s/ R. D. FAGAN
		R. D. FAGAN, Chairman of the Board, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on March 7, 2003:

Signature		Title

/s/ R. D. FAGAN R. D. FAGAN		Chairman of the Board, President, Director and Chief Executive Officer (Principal Executive Officer)

/s/ G. L. GILLETTE G. L. GILLETTE		Senior Vice President-Finance and Chief Financial Officer (Principal Financial Officer)

/s/ S. A. MYERS S. A. MYERS		Vice President-Corporate Accounting and Tax (Principal Accounting Officer)

Signature	Title	Signature	Title

C. D. AUSLEY* C. D. AUSLEY	Director	T. L. RANKIN* T. L. RANKIN	Director

S. L. BALDWIN* S. L. BALDWIN	Director	W. D. ROCKFORD* W. D. ROCKFORD*	Director

J. L. FERMAN, JR.* J. L. FERMAN, JR.	Director	W. P. SOVEY* W. P. SOVEY	Director

L. GUINOT, JR.* L. GUINOT, JR.	Director	J. T. TOUCHTON* J. T. TOUCHTON	Director

I. D. HALL* I. D. HALL	Director	J. A. URQUHART* J. A. URQUHART	Director

S. W. HUDSON* S. W. HUDSON	Director	J. O. WELCH, JR.* J. O. WELCH, JR.	Director


*By:		/s/ G. L. GILLETTE
		G. L. GILLETTE, Attorney-in-fact

132

CERTIFICATIONS

I, Robert D. Fagan, certify that:

I have reviewed this annual report on Form 10-K of TECO Energy, Inc.;

Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 7, 2003				/s/ R. D. FAGAN
				R. D. FAGAN
				Chairman of the Board, President, Director and Chief Executive Officer
				(Principal Executive Officer)

133

CERTIFICATIONS

I, Gordon L. Gillette, certify that:

I have reviewed this annual report on Form 10-K of TECO Energy, Inc.;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: March 7, 2003				/s/ G. L. GILLETTE
				G. L. GILLETTE
				Senior Vice President—Finance and Chief Financial Officer
				(Principal Financial Officer)

134

SIGNATURES

		TAMPA ELECTRIC COMPANY

By:		/s/ R. D. FAGAN
		R. D. FAGAN, Chairman of the Board, Director and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on March 7, 2003:

Signature		Title

/s/ R. D. FAGAN R. D. FAGAN		Chairman of the Board, Director and Chief Executive Officer Senior Vice President-Finance

/s/ G. L. GILLETTE G. L. GILLETTE		Senior Vice President-Finance and Chief Financial Officer (Principal Financial Officer)

/s/ P. L. BARRINGER P. L. BARRINGER		Vice President-Controller (Principal Accounting Officer)

Signature	Title	Signature	Title

C. D. AUSLEY* C. D. AUSLEY	Director	T. L. RANKIN* T. L. RANKIN	Director

S. L. BALDWIN* S. L. BALDWIN	Director	W. D. ROCKFORD* W. D. ROCKFORD*	Director

J. L. FERMAN, JR.* J. L. FERMAN, JR.	Director	W. P. SOVEY* W. P. SOVEY	Director

L. GUINOT, JR.* L. GUINOT, JR.	Director	J. T. TOUCHTON* J. T. TOUCHTON	Director

I. D. HALL* I. D. HALL	Director	J. A. URQUHART* J. A. URQUHART	Director

S. W. HUDSON* S. W. HUDSON	Director	J. O. WELCH, JR.* J. O. WELCH, JR.	Director


*By:		/s/ G. L. GILLETTE
		G. L. GILLETTE, Attorney-in-fact

135

CERTIFICATIONS

I, Robert D. Fagan, certify that:

I have reviewed this annual report on Form 10-K of Tampa Electric Company;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: March 7, 2003				/s/ R. D. FAGAN
				R. D. FAGAN
				Chairman of the Board, President, Director and Chief Executive Officer
				(Principal Executive Officer)

136

CERTIFICATIONS

I, Gordon L. Gillette, certify that:

I have reviewed this annual report on Form 10-K of Tampa Electric Company;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: March 7, 2003				/s/ G. L. GILLETTE
				G. L. GILLETTE
				Senior Vice President—Finance and Chief Financial Officer
				(Principal Financial Officer)

137

Supplemental Information to Be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act

No annual report or proxy material has been sent to Tampa Electric Company’s security holders because all of its equity securities are held by TECO Energy, Inc.

138

INDEX TO EXHIBITS

Exhibit No.	Description	Page No.

3.1	Articles of Incorporation of TECO Energy, Inc., as amended on April 20, 1993 (Exhibit 3, Form 10-Q for the quarter ended March 31, 1993 of TECO Energy, Inc.).	*

3.2	Bylaws of TECO Energy, Inc., as amended effective Jan. 18, 2001 (Exhibit 3.2, Form 10-K 2000 of TECO Energy, Inc.).	*

3.3	Articles of Incorporation of Tampa Electric Company (Exhibit 3, to Registration Statement No. 2-70653).	*

3.2	Bylaws of Tampa Electric Company, as amended effective Apr. 16, 1997 (Exhibit 3 Form 10-Q for the quarter ended June 30, 1997 of Tampa Electric Company).	*

4.1	Indenture of Mortgage among Tampa Electric Company, State Street Trust Company and First Savings & Trust Company of Tampa, dated as of Aug. 1, 1946 (Exhibit 7-A to Registration Statement No. 2-6693).	*

4.2	Thirteenth Supplemental Indenture, dated as of Jan. 1, 1974, to Exhibit 4.1 (Exhibit 2-g-1, Registration Statement No. 2-51204).	*

4.3	Sixteenth Supplemental Indenture, dated as of Oct. 30, 1992, to Exhibit 4.1 (Exhibit 4.1, Form 10-Q for the quarter ended Sept. 30, 1992 of TECO Energy, Inc.).	*

4.4	Eighteenth Supplemental Indenture, dated as of May 1, 1993, to Exhibit 4.1 (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 1993 of TECO Energy, Inc.).	*

4.5	Installment Purchase Contract between the Hillsborough County Industrial Development Authority and Tampa Electric Company, dated as of Jan. 31, 1984 (Exhibit 4.13, Form 10-K for 1993 of TECO Energy, Inc.).	*

4.6	First Supplemental Installment Purchase Contract, dated as of Aug. 2, 1984 (Exhibit 4.14, Form 10-K for 1994 of TECO Energy, Inc.).	*

4.7	Second Supplemental Installment Purchase Contract, dated as of July 1, 1993 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 1993 of TECO Energy, Inc.).	*

4.8	Loan and Trust Agreement among the Hillsborough County Industrial Development Authority, Tampa Electric Company and NCNB National Bank of Florida, as trustee, dated as of Sept. 24, 1990 (Exhibit 4.1, Form 10-Q for the quarter ended Sept. 30, 1990 for TECO Energy, Inc.).	*

4.9	Loan and Trust Agreement among the Hillsborough County Industrial Development Authority, Tampa Electric Company and NationsBank of Florida, N.A., as trustee, dated as of Oct. 26, 1992 (Exhibit 4.2, Form 10-Q for the quarter ended Sept. 30, 1992 of TECO Energy, Inc.).	*

4.10	Loan and Trust Agreement among the Hillsborough County Industrial Development Authority, Tampa Electric Company and NationsBank of Florida, N.A., as trustee, dated as of June 23, 1993 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 1993 of TECO Energy, Inc.).	*

4.11	Loan and Trust Agreement among Hillsborough County Industrial Development Authority, Tampa Electric Company and The Bank of New York Trust Company of Florida, as trustee, dated as of June 1, 2002. (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2002 of TECO Energy, Inc.).	*

4.12	Loan and Trust Agreement, dated as of Dec. 1, 1996, among the Polk County Industrial Development Authority, Tampa Electric Company and The Bank of New York, as trustee (Exhibit 4.22, Form 10-K for 1996 of TECO Energy, Inc.).	*

4.13	Installment Sales Agreement between the Plaquemines Port, Harbor and Terminal District (Louisiana) and Electro-Coal Transfer Corporation, dated as of Sept. 1, 1985 (Exhibit 4.19, Form 10-K for 1986 of TECO Energy, Inc.).	*

4.14	First Supplemental Installment Sales Agreement, between Plaquemines Port, Harbor, and Terminal District (Louisiana) and Electro-Coal Transfer Corporation, dated Dec. 20, 2000 (Exhibit 4.20, Form 10-K for 2000 of TECO Energy, Inc.).	*

4.15	Amended and Restated Reimbursement Agreement between TECO Energy, Inc. and Electro-Coal Transfer LLC, dated as of Apr. 5, 2001 (Exhibit 4.1, Form 8-K date Apr. 5, 2001 of TECO Energy, Inc.).	*

4.16	Indenture between Tampa Electric Company and The Bank of New York, as trustee, dated as of July 1, 1998 (Exhibit 4.1, Registration Statement No. 333-55873)	*

139


4.17	Third Supplemental Indenture between Tampa Electric Company and The Bank of New York, as trustee, dated as of June 15, 2001 (Exhibit 4.2, Form 8-K dated June 25, 2001 of Tampa Electric Company).	*

4.18	Fourth Supplemental Indenture between Tampa Electric Company and The Bank of New York, as trustee, dated as of Aug. 15, 2002. (Exhibit 4.2, Form 8-K dated Aug. 26, 2002 of Tampa Electric Company).	*

4.19	Credit Agreement dated as of Nov. 13, 2002, among Tampa Electric Company as Borrower, Citibank, N.A., as Administrative Agent, Salomon Smith Barney Inc. and The Bank of New York, As Co-Lead Arrangers, Morgan Stanley Senior Funding, Inc., and The Bank of New York, as Co-Syndication Agents, Bank of America, N.A., as Documentation Agent and the lenders parties Thereto as Lenders (Exhibit 4.1, Form 8-K dated Nov. 13, 2002 for TECO Energy, Inc.).	*

4.20	Indenture between TECO Energy, Inc. and The Bank of New York, as trustee, dated as of Aug. 17, 1998 (Exhibit 4.1, Form 8-K dated Sept. 20, 2000 of TECO Energy, Inc.).	*

4.21	Second Supplemental Indenture dated as of Aug. 15, 2000 between TECO Energy, Inc. and The Bank of New York (Exhibit 4.1, Form 8-K dated Sept. 28, 2000 of TECO Energy, Inc.).	*

4.22	Third Supplemental Indenture dated as of Dec. 1, 2000 between TECO Energy, Inc. and The Bank of New York, as trustee (Exhibit 4.21, Form 8-K dated Dec. 21, 2000 of TECO Energy, Inc.).	*

4.23	Amended and Restated Limited Liability Company Agreement of TECO Funding Company I, LLC dated as of Dec. 1, 2000 (Exhibit 4.24, Form 8-K dated Dec. 21, 2000 of TECO Energy, Inc.).	*

4.24	Amended and Restated Trust Agreement of TECO Capital Trust I among TECO Funding Company I, LLC, The Bank of New York and The Bank of New York (Delaware) dated as of Dec. 1, 2000 (Exhibit 4.22, Form 8-K dated Dec. 21, 2000 of TECO Energy, Inc.).	*

4.25	Guaranty Agreement between TECO Energy, Inc. and The Bank of New York, as trustee, dated as of Dec. 1, 2000 (Exhibit 4.25, Form 8-K dated Dec. 21, 2000 of TECO Energy, Inc.).	*

4.26	Fourth Supplemental Indenture dated as of Apr. 30, 2001 between TECO Energy, Inc. and The Bank of New York, as trustee (Exhibit 4.28, Form 8-K dated May 1, 2001 of TECO Energy, Inc.).	*

4.27	Fifth Supplemental Indenture dated as of Sept. 10, 2001 between TECO Energy, Inc. and The Bank of New York, as trustee (Exhibit 4.16, Form 8-K dated Sept. 26, 2001 of TECO Energy, Inc.).	*

4.28	Sixth Supplemental Indenture dated as of Jan. 15, 2002 between TECO Energy, Inc. and The Bank of New York, as trustee (Exhibit 4.28, Form 8-K dated Jan. 15, 2002 of TECO Energy, Inc.).	*

4.29	Purchase Contract Agreement between TECO Energy, Inc. and The Bank of New York, as Purchase Contract Agent, dated as of Jan. 15, 2002 (Exhibit 4.29, Form 8-K dated Jan. 15, 2002 of TECO Energy, Inc.).	*

4.30	Amended and Restated Trust Agreement of TECO Capital Trust II among TECO Funding Company II, LLC, The Bank of New York and The Bank of New York (Delaware), dated as of Jan. 15, 2002 (Exhibit 4.31, Form 8-K dated Jan. 15, 2002 of TECO Energy, Inc.).	*

4.31	Amended and Restated Limited Liability Agreement of TECO Funding Company II, LLC, dated as of Jan. 15, 2002 (Exhibit 4.33, Form 8-K dated Jan. 15, 2002 of TECO Energy, Inc.).	*

4.32	Guarantee Agreement by and between TECO Energy, Inc., as Guarantor and The Bank of New York, dated as of Jan. 15, 2002 (Exhibit 4.35, Form 8-K dated Jan. 15, 2002 of TECO Energy, Inc.).	*

4.33	Form of Remarketing Agreement by and between TECO Energy, Inc. and the Remarketing Agent (Exhibit 4.37, Form 8-K dated Jan. 15, 2002 of TECO Energy, Inc.).	*

4.34	Pledge Agreement among TECO Energy, Inc., The Bank of New York, as Collateral Agent, Custodial Agent and Securities Intermediary and The Bank of New York, as Purchase Contract Agent dated as of Jan. 15, 2002 (Exhibit 4.38, Form 8-K dated Jan. 15, 2002 of TECO Energy, Inc.).	*

4.35	Seventh Supplemental Indenture dated as of May 1, 2002 between TECO Energy, Inc. and The Bank of New York, as trustee (Exhibit 4.15, Form 8-K dated May 13, 2002 of TECO Energy, Inc.).	*

4.36	Eighth Supplemental Indenture dated as of Nov. 20, 2002 between TECO Energy, Inc. and The Bank of New York, as trustee (Exhibit 4.1, Form 8-K dated Nov. 20, 2002 for TECO Energy, Inc.).	*

140


4.37	Credit Agreement dated as of Nov. 14, 2001, among TECO Energy, Inc., as Borrower, Citibank. N.A., as Administrative Agent, Salomon Smith Barney Inc. and Banc of America Securities, LLC, as Co-Lead Arrangers, Banc of America, as Syndication Agent, the Bank of Nova Scotia, BNP Paribas and SunTrust Bank, as Co-Documentation Agents, JP Morgan Chase Bank, LC Issuing Bank, and the lenders parties thereto as Lenders (Exhibit 4.41, Form 10-K for 2001 of TECO Energy, Inc.).	*

4.38	Renewed Rights Agreement between TECO Energy, Inc. and BankBoston, N.A., as Rights Agent, dated as of Oct. 21, 1998 (Exhibit 4, Form 8-K, dated as of Oct. 21, 1998 of TECO Energy, Inc.).	*

10.1	TECO Energy Group Supplemental Executive Retirement Plan, as amended and restated as of July 1, 1998, as further amended as of July 15, 1998. (Exhibit 10.1, Form 10-K for 2001 of TECO Energy, Inc.).	*

10.2	TECO Energy Group Supplemental Retirement Benefits Trust Agreement, as amended and restated as of Jan. 1, 1998, as further amended as of July 15, 1998. (Exhibit 10.2, Form 10-K for 2001 of TECO Energy, Inc.).	*

10.3	Annual Incentive Compensation Plan for TECO Energy and subsidiaries, revised as of April 17, 2002. (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2002 for TECO Energy, Inc.).	*

10.4	TECO Energy Group Supplemental Disability Income Plan, dated as of March 20, 1998 (Exhibit 10.22, Form 10-K for 1988 of TECO Energy, Inc.).	*

10.5	Forms of Severance Agreement between TECO Energy, Inc. and certain officers, as amended and restated as of Oct. 22, 1999 (Exhibit 10.7, Form 10-K for 1999 of TECO Energy, Inc.).	*

10.6	Loan and Stock Purchase Agreement between TECO Energy, Inc. and Barnett Banks Trust Company, N.A., as trustee of the TECO Energy Group Savings Plan Trust Agreement (Exhibit 10.3, Form 10-Q for the quarter ended March 31, 1990 for TECO Energy, Inc.).	*

10.7	TECO Energy Directors’ Deferred Compensation Plan, as amended and restated effective as of April 1, 1994 (Exhibit 10.1, Form 10-Q for the quarter ended March 31, 1994 for TECO Energy, Inc.).	*

10.8	TECO Energy Group Deferred Compensation Plan (previously the TECO Energy Group Retirement Savings Excess Benefit Plan), as amended and restated effective as of Oct. 17, 2001. (Exhibit 10.8, Form 10-K for 2001 of TECO Energy, Inc.).	*

10.9	Compensation Committee’s Determinations Regarding Credit Rates for the TECO Energy Group Deferred Compensation Plan. (Exhibit 10.2, Form 10-Q for the quarter ended Mar. 31, 2002 of TECO Energy, Inc.).	*

10.10	TECO Energy, Inc. 1996 Equity Incentive Plan as amended Apr. 18, 2001 (Exhibit 10.1, Form 10-Q for the quarter ended March 31, 2001 of TECO Energy, Inc.).	*

10.11	Form of Nonstatutory Stock Option under the TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 1996 of TECO Energy, Inc.).	*

10.12	Form of Amendment to Nonstatutory Stock Option, dated as of July 15, 1998, under the TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit 10.3, Form 10-Q for the quarter ended Sept. 30, 1998 of TECO Energy, Inc.).	*

10.13	Form of Nonstatutory Stock Option under the TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit 10.5, Form 10-Q for the quarter ended June 30, 1999 of TECO Energy, Inc.).	*

10.14	Form of Restricted Stock Agreement between TECO Energy, Inc. and certain officers under the TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 1998 of TECO Energy, Inc.).	*

10.15	Form of Amendment to Restricted Stock Agreements, dated as of July 15, 1998, TECO Energy, Inc. and certain officers under the TECO Energy, Inc. between 1996 Equity Incentive Plan (Exhibit 10.2, Form 10-Q for the quarter ended Sept. 30, 1998 of TECO Energy, Inc.).	*

10.16	TECO Energy, Inc. 1997 Director Equity Plan (Exhibit 10.1, Form 8-K dated April 16, 1997 of TECO Energy, Inc.).	*

10.17	Form of Nonstatutory Stock Option under the TECO Energy, Inc. 1997 Director Equity Plan (Exhibit 10, Form 10-Q for the quarter ended June 30, 1997 of TECO Energy, Inc.).	*

10.18	Supplemental Executive Retirement Plan for R. K. Eustace as of Jan. 15, 1997 (Exhibit 10.24, Form 10-K for 1997 of TECO Energy, Inc.).	*

10.19	Supplemental Executive Retirement Plan for R. D. Fagan as amended (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2001 of TECO Energy, Inc.).	*

10.20	Nonstatutory Stock Option granted to R. D. Fagan, dated as of May 24, 1999, under the TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit 10.3, Form 10-Q for the quarter ended June 30, 1999 of TECO Energy, Inc.).	*

141


10.21	Restricted Stock Agreement between TECO Energy, Inc. and R. D. Fagan, dated as of May 24, 1999 (Exhibit 10.4, Form 10-Q for the quarter ended June 30, 1999 of TECO Energy, Inc.).	*

10.22	Severance Agreement between TECO Energy, Inc. and R.D. Fagan, as amended (Exhibit 10.2, form 10-Q for the quarter ended June 30, 2001 of TECO Energy, Inc.).	*

10.23	Form of Performance Shares Agreement between TECO Energy, Inc. and certain officers under the TECO Energy, Inc. 1996 Equity Incentive Plan. (Exhibit 10.7, Form 10-Q for the quarter ended June 30, 2000 of TECO Energy, Inc.).	*

10.24	Form of 2002 Amendment to TECO Performance Shares Agreements between TECO Energy, Inc., and certain officers under the TECO Energy Inc. 1996 Equity Incentive Plan. (Exhibit 10.25, Form 10-K for 2001 of TECO Energy, Inc.).	*

10.25	Form of Performance Shares Agreement between TECO Energy, Inc. and certain TECO Power Services Corporation officers under the TECO Energy, Inc. 1996 Equity Incentive Plan. (Exhibit 10.3, Form 10-Q for the quarter ended June 30, 2000 of TECO Energy, Inc.).	*

10.26	Supplemental Executive Retirement Plan for R. Lehfeldt as of Apr. 17, 2002. (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2002 of TECO Energy, Inc.).	*

10.27	Form of Restricted Stock Agreement between TECO Energy, Inc. and certain officers under the TECO Energy, Inc. 1996 Equity Incentive Plan, dated as of Jan. 28, 2003.	[ ]

10.28	Form of Nonstatutory Stock Option under the TECO Energy, Inc. 1997 Director Equity Plan, dated as of Jan. 29, 2003.	[ ]

10.29	Equity Contribution Guaranty Agreement between TECO Energy, Inc., and Citibank, N.A., as Administrative Agent under the Union Power Project Credit Agreement (Exhibit 10.4, Form 10-Q for the quarter ended June 30, 2001 of TECO Energy, Inc.).	*

10.30	Equity Bridge Guaranty Agreement between TECO Energy, Inc., and Citibank, N.A., as Administrative Agent under the Union Power Project Bridge Loan Agreement (Exhibit 10.5, form 10-Q for the quarter ended June 30, 2001 of TECO Energy, Inc.).	*

10.31	Contingent Equity Contribution Guaranty Agreement between TECO Energy, Inc., and Citibank, N.A., as Administrative Agent under the Gila River Project Credit Agreement (Exhibit 10.6, Form 10-Q for the quarter ended June 30, 2001 of TECO Energy, Inc.).	*

10.32	Equity Contribution Guaranty Agreement between TECO Energy, Inc., and Citibank, N.A., as Administrative Agent under the Gila River Project Credit Agreement (Exhibit 10.7, Form 10-Q for the quarter ended June 30, 2001 of TECO Energy, Inc.).	*

10.33	Equity Bridge Guaranty Agreement between TECO Energy, Inc., and Citibank, N.A., as Administrative Agent under the Gila River Bridge Loan Agreement (Exhibit 10.8, Form 10-Q for the quarter ended June 30, 2001 of TECO Energy, Inc.).	*

10.34	Omnibus Amendment to TECO guarantees related to the Union Power Project, dates as of Oct. 31, 2001, by and among TECO Energy, Inc., Guarantor, and Administrative Agent (Exhibit 10.4, Form 10-Q for the quarter ended June 30, 2002 of TECO Energy, Inc.).	*

10.35	Omnibus Amendment to TECO Guarantees related to the Gila River Project, dated as of Oct. 31, 2001, by and among TECO Energy, Inc., Guarantor, and Administrative Agent. (Exhibit 10.3, Form 10-Q for the quarter ended June 30, 2002 of TECO Energy, Inc.).	*

10.36	Amended and Restated Construction Contract Undertaking by TECO Energy, Inc. in favor of Union Power Partners, L.P., as Borrower, and Citibank, N.A., as Administrative Agent under the Union Power Project Credit Agreement, dated as of May 14, 2002 (Exhibit 99.5 to Registration Statement No. 333-102019.	*

10.37	Amended and Restated Construction Contract Undertaking by TECO Energy, Inc. in favor of Panda Gila River, L.P., as Borrower, and Citibank. N.A., as Administrative Agent under the Gila River Project Credit Agreement, dated a1s of May 14, 2002 (Exhibit 99.4 to Registration Statement No. 333-102019).	*

10.38	Consent and Acceleration Agreement dated as of Feb. 7, 2002 by and among TECO Power Services Corporation, TECO Energy, Inc., TPS GP, Inc., TPS LP, Inc., Panda GS V, LLC, Panda GS VI, LLC, Panda Energy International, Inc. and Bayerische Hypo-Und Vereinsbank AG, New York Branch.	[ ]

12.1	Ratio of Earnings to Fixed Charges – TECO Energy, Inc.	[ ]

12.2	Ratio of Earnings to Fixed Charges – Tampa Electric Company.	[ ]

21.	Subsidiaries of the Registrant.	[ ]

23.1	Consent of Independent Certified Public Accountants – TECO Energy, Inc.	[ ]

23.2	Consent of Independent Certified Public Accountants – Tampa Electric Company.	[ ]

24.1.1	Power of Attorney – TECO Energy, Inc.	[ ]

24.1.2	Power of Attorney – Tampa Electric Company.	[ ]

24.2.1	Certified copy of resolution authorizing Power of Attorney – TECO Energy, Inc.	[ ]

24.2.2	Certified copy of resolution authorizing Power of Attorney – Tampa Electric Company.	[ ]

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Indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. Exhibits filed with periodic reports of TECO Energy, Inc. and Tampa Electric Company were filed under Commission File Nos. 1-8180 and 1-5007, respectively.

Certain instruments defining the rights of holders of long-term debt of TECO Energy, Inc. and its consolidated subsidiaries authorizing in each case a total amount of securities not exceeding 10 percent of total assets on a consolidated basis are not filed herewith. TECO Energy, Inc. will furnish copies of such instruments to the Securities and Exchange Commission upon request.

Certain instruments defining the rights of holders of long-term debt of Tampa Electric Company authorizing in each case a total amount of securities not exceeding 10 percent of total assets on a consolidated basis are not filed herewith. Tampa Electric Company will furnish copies of such instruments to the Securities and Exchange Commission upon request.

Executive Compensation Plans and Arrangements

Exhibits 10.1 through 10.5 and 10.7 through 10.28 above are management contracts or compensatory plans or arrangements in which executive officers or directors of TECO Energy, Inc. participate.

143