Back to GetFilings.com

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 2004

OR

For the transition period from              to             

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

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

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.    YES  x    NO  ¨

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

Indicate by check mark whether TECO Energy, Inc. is an accelerated filer (as defined in Exchange Act Rule 12b-2).    YES  x     NO  ¨

Indicate by check mark whether Tampa Electric Company is an accelerated filer (as defined in Exchange Act Rule 12b-2).    YES   ¨    NO  x

The aggregate market value of TECO Energy, Inc.’s common stock held by nonaffiliates of the registrant as of June 30, 2004 was $2,259,962,775.

The aggregate market value of Tampa Electric Company’s common stock held by nonaffiliates of the registrant as of June 30, 2004 was zero.

The number of shares of TECO Energy, Inc.’s common stock outstanding as of February 28, 2005 was 206,890,488. As of February 28, 2005, 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 2005 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.

Index to Exhibits begins on page 167

Table of Contents

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 5,543 employees as of Dec. 31, 2004.

TECO Energy’s Corporate Governance Guidelines, the charter of each committee of the Board of Directors, and the code of ethics applicable to all directors, officers and employees, the Standards of Integrity, are available on the Investor Relations page of TECO Energy’s website, www.tecoenergy.com, or in print free of charge to any investor who requests the information. TECO Energy also makes its Securities and Exchange Commission (SEC) (www.sec.gov) filings available free of charge on the Investor Relations page of TECO Energy’s website.

TECO Energy currently owns no operating assets but holds all of the common stock of Tampa Electric Company and directly, or through its subsidiaries TECO Diversified, Inc. or TECO Wholesale Generation, Inc., the other subsidiaries listed below. Unless otherwise indicated by the context, “TECO Energy” means the holding company, TECO Energy, Inc., and its subsidiaries, and references to individual subsidiaries of TECO Energy, Inc. refer to that company and its respective subsidiaries. TECO Energy is a public utility holding company exempt from registration under the Public Utility Holding Company Act of 1935.

TECO Energy is a holding company for regulated utilities and other unregulated businesses. TECO Energy’s significant business segments and, revenues for those segments for the years indicated, are identified below.

Tampa Electric Company, a Florida corporation and TECO Energy’s largest subsidiary has two business segments, and through its Tampa Electric division (Tampa Electric) provides retail electric service to more than 625,000 customers in West Central Florida with a net winter system generating capability of 4,421 megawatts (MW). Peoples Gas System (PGS), a division of Tampa Electric Company, is engaged in the purchase and distribution of natural gas for residential, commercial, industrial and electric power generation customers in Florida. With more than 314,000 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 2004 was 1.1 billion therms.

TECO Coal Corporation (TECO Coal), a Kentucky corporation, owns no operating assets but owns all of the common stock of, or membership interests in, 13 subsidiaries which own mineral rights, and own or operate surface and underground mines, synthetic fuel production facilities, and coal processing and loading facilities in eastern Kentucky, Tennessee and southwestern Virginia.

TECO Transport Corporation (TECO Transport), a Florida corporation, owns no operating assets but owns all of the common stock of, or membership interests in, eight subsidiaries which provide waterborne transportation, storage and transfer services of coal and other dry-bulk commodities.

TECO Energy’s other unregulated companies with continuing operations include TWG Non-Merchant, Inc. (Non-Merchant), TECO Solutions, Inc. (TECO Solutions), TECO Properties, Inc. (TECO Properties), and TECO Investments, Inc. Non-Merchant primarily has investments in unconsolidated subsidiaries that participate in independent power projects and electric distribution in Guatemala. TECO Solutions’ subsidiaries, many of which were sold in 2004 as part of TECO Energy’s renewed focus on core utility and profitable operations, primarily provided mechanical contracting, air conditioning, electrical and plumbing systems and repair and maintenance services in Florida (see the Discontinued Operations discussion below).

TWG Merchant, Inc. (TWG-Merchant), a Florida corporation, has subsidiaries that have interests in independent power projects in Virginia, Arkansas, Mississippi and Arizona. TWG-Merchant continuing operations includes the results of operations for the Commonwealth Chesapeake power station, the sale of which is expected to close near the end of March 2005, Dell and McAdams power plants that are not expected to be completed, as well as the equity investment in other U.S. merchant plants that were sold in 2004, and TECO EnergySource, Inc. (TES), the energy marketing operation for the merchant plants.

Revenues for TECO Energy’s significant business segments for the years indicated is below.

Revenues from Continuing Operations

1

Table of Contents

For additional financial information regarding TECO Energy’s significant business segments including geographic areas, see Note 14 to the TECO Energy Consolidated Financial Statements.

Discontinued Operations

TECO Energy’s other unregulated companies completed several dispositions in 2004, 2003 and 2002, as part of the business strategy change to focus on the electric and gas utilities and long-term profitable unregulated businesses and to reduce exposure to the merchant power sector (see Overview section of MD & A). In July 2004, Non-Merchant’s 50% indirect interest in the Hamakua Power Station in Hawaii was sold. TECO BGA, Inc., TECO AGC, Ltd., and substantially all the assets of Prior Energy also were sold in 2004. Hardee Power Partners, Ltd. (HPP) and substantially all the net assets of TECO Gas Services were sold in 2003, and substantially all the assets of TECO Coalbed Methane were sold in 2002. Additionally, at Dec. 31, 2004, TECO Energy was committed to a plan to sell BCH Mechanical and TECO Thermal, both investments of TECO Solutions. As such, the assets and liabilities of BCH Mechanical and TECO Thermal are designated as held for sale at Dec. 31, 2004. The sale of BCH Mechanical was completed in January 2005. See Note 23 to the TECO Energy Consolidated Financial Statements for additional information. Results for BCH Mechanical, TECO AGC, Ltd, TECO BGA, TECO Thermal, TECO Coalbed Methane, and Prior Energy have been accounted for as discontinued operations for all periods reported. HPP is accounted for in continuing operations because of the continuing involvement of Tampa Electric through a pre-existing agreement to purchase power from HPP. In January 2004, TECO Energy completed the sale of its general and limited partnership interests in Heritage Propane Partners, L.P. as a part of a larger transaction that involved the merging of privately held Energy Transfer Company with Heritage Propane Partners. Revenues from the discontinued operations of other unregulated companies were $50.4 million, $100.1 million and $122.0 million for the years ended Dec. 31, 2004, 2003 and 2002, respectively.

TWG-Merchant’s interest in the Union and Gila River project companies, which own merchant generation plants in Arkansas and Arizona, respectively, is held by an indirect wholly owned subsidiary of TWG-Merchant, TECO-Panda Generating Company, L.P. (TPGC). TPGC was part of the TWG-Merchant operating segment until designated as assets held for sale in December 2003. As of Dec. 31, 2003, TECO Energy management was committed to a plan to sell TECO Energy’s indirect ownership of the equity or net assets of TPGC through a sale and transfer agreement to the lenders of ownership of these plants. As of Dec. 31, 2004, management expects to complete the transfer of TPGC in 2005, and therefore the assets and liabilities of TPGC continue to be reported as held for sale. To facilitate the completion of this transaction, the lending group approved a pre-negotiated Chapter 11 bankruptcy case for the Union and Gila River project entities. TPGC’s results are accounted for as discontinued operations for all periods reported. Revenues from the discontinued operations of TPGC in 2004 and 2003 were $510.7 million and $319.4 million, respectively. TPGC had no revenues in 2002.

In August 2004, a subsidiary of TWG-Merchant completed the sale of its 50% indirect interest in Texas Independent Energy, LP (TIE). In December 2004, TWG-Merchant also completed the sale of Frontera Generation Limited Partnership (Frontera), the owner of the Frontera Power Station in Texas. Frontera’s results are accounted for as discontinued operations for all periods reported. Revenues from the discontinued operation of Frontera in 2004, 2003 and 2002 were $61.6 million, $63.1 million and $83.1 million, respectively. See Notes 16 and 21 to the TECO Energy Consolidated Financial Statements for additional information.

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, with 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 two 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 2,380 employees as of Dec. 31, 2004, of which 896 were represented by the International Brotherhood of Electrical Workers and 220 were represented by the Office and Professional Employees International Union.

2

Table of Contents

In 2004, approximately 49% of Tampa Electric’s total operating revenue was derived from residential sales, 30% from commercial sales, 10% from industrial sales and 11% from other sales, including bulk power sales for resale. The sources of operating revenue and megawatt-hour sales for the years indicated were as follows:

No significant part of Tampa Electric’s business is dependent upon a single customer or a few customers, the loss of any one or more of whom would have a significant adverse effect on Tampa Electric. The Mosaic Company, a large phosphate producer, is Tampa Electric’s largest customer and represents less than 3% of Tampa Electric’s 2004 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 the use of air conditioning and other cooling equipment.

Regulation

The retail operations of Tampa Electric are regulated by the Florida Public Service Commission (FPSC or the Commission), 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.

Tampa Electric’s rates and allowed return on equity (ROE) range of 10.75% to 12.75% with a midpoint of 11.75% 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 without a base rate increase, even with the rate base additions associated with the repowering of the H. L. Culbreath Bayside Power Station (Bayside).

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 2004, 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 2005. In November, the FPSC approved Tampa Electric’s requested changes. The rates include the impacts of increased natural gas and coal prices, the collection of underestimated 2004 fuel expenses, the proceeds from the sale of sulfur dioxide (SO₂) emissions allowances associated with Hookers Point Station and the operating and maintenance (O&M) costs associated with the Big Bend Units 1 – 3 pre-selective catalytic reduction (SCR) projects required by the Environmental Protection Agency (EPA) Consent Decree and Florida Department of Environmental Protection (FDEP) Consent Final Judgment. In addition, the rates also reflect the

3

Table of Contents

Commission’s September 2004 decision to reduce the annual cost recovery amount for water transportation services for coal and petroleum coke provided under Tampa Electric’s contract with TECO Transport described below. The 2004 costs associated with this disallowance were recognized in 2004. See Regulation – Tampa Electric Rate Strategy and Regulation – Cost Recovery Clauses-Tampa Electric sections 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 also the Regulation – Regional Transmission Organization (RTO) section 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 section below).

The transactions between Tampa Electric and its 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. For information about Tampa Electric’s contract for coal transportation and dry-bulk storage services with TECO Transport, see the Regulation – Coal Transportation Contract section of MD&A.

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 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.

In 1999, the FERC approved a three-year market-based sales tariff for Tampa Electric, which allows Tampa Electric to sell excess wholesale 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.

In November 2004, Tampa Electric and the market-based rate authorized entities within TECO Energy filed a triennial market power study update. On Mar. 2, 2005, after a review of that filing and supporting information, the FERC determined that Tampa Electric had failed certain tests for market power within certain regions of Florida. The FERC has instituted an investigation of Tampa Electric’s potential market power in those regions and ordered that Tampa Electric make a compliance filing to determine if Tampa Electric has market power in other regions of the state. If it is determined that Tampa Electric has market power in those regions in question, it could lose its market-based rate authorization for only those regions, and, therefore make wholesale power sales at cost-based rates rather than market-based rates. Tampa Electric intends to comply with all of the filing requirements and is evaluating the appropriate response to the FERC’s order (see Regulation – FERC Market Power Test section of MD&A).

There is presently 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 2003, the FPSC implemented rules that modified rules from 1994 that required investor-owned electric utilities (IOUs) to issue RFP’s prior to filing a petition for Determination of Need for construction of a power plant with a steam cycle greater than 75 megawatts. The new rules became effective for requests for proposal for applicable capacity additions, prospectively. See Regulation – Utility Competition-Electric section of MD&A.

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.

In 2004, FERC also issued Standards of Conduct for Transmission Providers to ensure that all transmission customers, affiliated and non-affiliated, are treated on a non-discriminatory basis. TECO Energy and its affiliates were compliant with the new rules by the required date of Nov. 19, 2004.

In December 1999, the FERC issued Order No. 2000, dealing with FERC’s continuing effort to affect open access to transmission facilities in large regional markets. In response, the peninsular Florida IOUs agreed to form an RTO to be known as GridFlorida LLC which would independently control the transmission assets of the filing utilities, as well as other utilities in

4

Table of Contents

the region that chose to join. In March 2001, the FERC conditionally approved GridFlorida, but in May 2001, the FPSC questioned the prudence of the three filing utilities joining GridFlorida. After an October 2001 hearing, the FPSC found that the companies were prudent in forming GridFlorida, but ordered the companies to modify their proposal to develop an RTO model that did not provide for the RTO to own the transmission assets. In August 2002, the FPSC voted to approve many of the compliance changes submitted, but set an October 2002 hearing on the market design changes proposed in the updated filing. In October 2002, the process was delayed when the Office of Public Counsel (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. Oral arguments occurred in May 2003, and the Florida Supreme Court dismissed the OPC appeal citing that it was premature because certain portions of the FPSC GridFlorida order are not final. In September 2003, a joint meeting of the FERC and FPSC took place to discuss wholesale market and RTO issues related to GridFlorida and in particular, federal/state interactions. During 2004, deliberations by the FPSC were put on hold to allow a consulting firm, engaged by the GridFlorida applicants, to conduct a cost/benefit study of the GridFlorida RTO. As a result, the FPSC held a series of collaborative meetings during the year with all interested parties to facilitate the development of the study methodology as well as participate in the submission of data required to complete the study. Upon conclusion of the study, which is expected to occur in the second quarter of 2005, the study results will be presented to the FPSC. The FPSC is then expected to make a determination as to whether to set the remaining items for hearing or to require the Florida IOUs to take other actions.

Fuel

Approximately 63% of Tampa Electric’s generation of electricity for 2004 was coal-fired, with natural gas representing approximately 36% and oil representing approximately 1%. Tampa Electric used its generating units to meet approximately 87% of the system load requirements, with the remaining 13% coming from purchased power. The percentage of total generation from coal was lower in 2004 than in previous years, as a result of Gannon’s repowering to the natural gas fueled 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:

Tampa Electric’s generating stations burn fuels as follows: Bayside 1, which went into commercial operation in April of 2003, and Bayside 2, which went into commercial operation in January of 2004, burn natural gas; Big Bend Station, which has sulfur dioxide scrubber capabilities, burns a combination of high-sulfur coal, petroleum coke and No. 2 fuel oil; Polk Power Station burns a blend of low-sulfur coal, high-sulfur coal, and petroleum coke which is gasified and subject to sulfur and particulate matter removal prior to combustion, natural gas and oil; and Phillips Station burns residual fuel oil.

Coal. Tampa Electric burned approximately 4.9 million tons of coal and petroleum coke during 2004 and estimates that its fuel consumption will be about 4.7 million tons for 2005. During 2004, Tampa Electric purchased approximately 68% of its coal under long-term contracts with six suppliers, and approximately 32% of its coal and petroleum coke in the spot market. Tampa Electric expects to obtain approximately 55% of its coal requirements in 2005 under long-term contracts with eight suppliers and the remaining 45% in the spot market. The level of spot market purchases for 2005 is expected to be above historical levels due to the test burning of various coals to determine sources of coal to be used after nitrogen oxide (NOx) controls are installed at the Big Bend Station. See the Environmental Compliance section of MD&A. Tampa Electric’s remaining long-term contracts provide for revisions in the base price to reflect changes in several important 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 by affiliated companies to Tampa Electric, see the TECO Transport section below.

In 2004, approximately 64% of Tampa Electric’s coal supply was deep-mined, approximately 25% 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.

5

Table of Contents

Natural Gas. In 2004, Tampa Electric contracted for 80% of the summer 2005 period expected gas needs and 65% for the winter 2005-2006 period. In the summer 2005, Tampa Electric expects to contract for an additional 20-30% of the winter 2005-2006 period and 20% of the summer 2006 period requirements. Additional volumes are expected to be procured on the short-term spot market.

Oil. Tampa Electric has in place agreements to purchase No. 2 oil, low sulfur No. 2 oil and No. 6 oil for its Big Bend, Polk and Phillips stations. All of these agreements have prices that are based on spot indices.

Franchises and Other Rights

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 that have franchise agreements with Tampa Electric, except for the cities of Oldsmar and Temple Terrace, 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 $29.7 million in 2004, 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, Pinellas County and Polk County agreements. The agreement covering electric operations in Pasco County expires in 2023.

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 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 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 SO₂, projects for NO_x reduction efforts on Big Bend Units 1 through 4, and the repowering of the coal-fired Gannon Station to natural gas. The commercial operation dates for the two repowered Bayside units were Apr. 24, 2003 and Jan. 15, 2004. The completed station has total station capacity of about 1,800 megawatts (nominal) of natural gas-fueled electric generation.

In 2004, Tampa Electric decided to install SCRs for NO_x control on Big Bend Unit 4, with an expected in-service date by Jun. 1, 2007. Tampa Electric has also decided to install SCRs on Big Bend Units 1, 2 and 3 with in-service dates for Unit 3 by May 1, 2008, Unit 2 by May 1, 2009 and Unit 1 by May 1, 2010. Tampa Electric has begun the detailed engineering and design of the SCR system. Tampa Electric’s capital investment forecast includes amounts in the 2005 through 2009 period for compliance with the NO_x, SO₂ and particulate matter reduction requirements (see Environmental Matter – Capital Expenditures section below).

Emission Reductions

Projects Tampa Electric has committed to under the Consent Decree and Consent Final Judgment will result in significant reductions in emissions. Since 1998, Tampa Electric has reduced annual SO₂, NO_x, and particulate matter (PM) emissions from its facilities by 161,642 tons, 39,066 tons, and 4,285 tons, respectively. Reductions in SO₂ emissions were accomplished through the installation of scrubber systems on Big Bend Units 1 and 2 in 1999. 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, as well. Currently, the scrubbers at Big Bend Station remove more than 95% of the SO₂ emissions from the flue gas streams. To date, these projects have resulted in the reduction of SO₂, NO_x and PM emissions 92%, 57%, and 82%, respectively, below 1998 levels.

6

Table of Contents

The repowering of Gannon Station to Bayside Power Station in April 2003 (Bayside Unit 1) and January 2004 (Bayside Unit 2) resulted in significant reduction in emissions of all pollutant types. Tampa Electric’s decision to install additional NO_x emissions controls on all Big Bend Units will result in the further reduction of emissions. By 2010, these projects are expected to result in the additional phased reduction of NO_x by 59,652 tons per year. In total, Tampa Electric’s emission reduction initiatives will result in the reduction of SO₂, NO_x and PM emissions by 89%, 87%, and 70%, respectively, below 1998 levels. With these improvements in place, Tampa Electric’s facilities will meet the same standards required of newer power generating facilities and help to significantly enhance the quality of the air in the community.

Due to pollution control co-benefits from the Consent Decree and Consent Final Judgment, reductions in mercury emissions have occurred due to the re-powering of Gannon Station to Bayside Station. At Bayside, where mercury levels have decreased 99% below 1998 levels, there are virtually zero mercury emissions. Additional mercury reductions are also anticipated from the installation of NO_x controls at Big Bend Station, which would lead to a mercury removal efficiency of approximately 70%.

The repowering of Gannon Station to Bayside Station will also lead to a significant reduction in carbon dioxide (CO₂) emissions. It is expected that in 2005, the repowering will result in a decrease in CO₂ emissions of approximately 5.1 million tons below 1998 levels. With this reduction, the Tampa Electric system CO₂ emissions will be in line with its 1990 CO₂ emission levels.

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a potentially responsible party (PRP) 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, 2004, Tampa Electric Company has estimated its ultimate financial liability to be approximately $17 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 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 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.

Capital Expenditures

During the five years ended Dec. 31, 2004, Tampa Electric spent $51.5 million, excluding the Gannon repowering, on capital additions to meet environmental requirements.

In total, Tampa Electric spent an estimated $12.3 million in 2004 on environmental projects. Environmental expenditures are estimated at $44.3 million for 2005 and an additional $354.9 million in total for 2006 through 2009. These totals include the expenditures required to comply with the EPA Consent Decree, which are discussed above.

In 2004, Tampa Electric spent approximately $6.7 million for compliance with the EPA consent decree requirements at Big Bend station for reduction of NO_x and PM emissions and to improve the scrubber systems to reduce S0₂ emissions. Since Tampa Electric has chosen to continue to burn coal at Big Bend station, further NO_x emission reductions are expected to require expenditures in 2005 estimated at $30.1 million and as much as $253.5 million being spent during 2006 through 2009 for the SCR equipment. Expenditures for the continued improvement of electrostatic precipitators for PM emissions reductions are expected to be $6.6 million during 2006 through 2009. Tampa Electric has also spent $661.1 million, excluding allowance for funds used during construction (AFUDC) and dismantlement, on Bayside Power Station, the repowering of the company’s coal-fired Gannon Station to use natural gas, to meet the EPA Consent Decree condition of eliminating coal-firing at Gannon Station.

7

Table of Contents

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 314,000 customers. The system includes approximately 9,900 miles of mains and over 5,800 miles of service lines. (See PGS’ Franchises section below.)

In 2004, the total throughput for PGS was 1.1 billion therms. Of this total throughput, 13% was gas purchased and resold to retail customers by PGS, 71% was third-party supplied gas that was delivered for retail transportation-only customers, and 16% was gas sold off-system. Industrial and power generation customers consumed approximately 61% of PGS’ annual therm volume, commercial customers used approximately 33%, 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 27% 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. Within the PGS operating territory, large cogeneration facilities utilize gas-fired technology in the production of electric power and steam.

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

PGS had 556 employees as of Dec. 31, 2004. A total of 87 employees in six of PGS’ 15 operating divisions are represented by various union organizations.

Regulation

The operations of PGS are regulated by the FPSC separately 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. For a description of recent proceeding activity, see the Regulation – Peoples Gas 2002 Rate Proceeding section of MD&A.

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through the purchased gas adjustment 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 – Peoples Gas 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; this charge is intended to permit PGS to recover its costs incurred 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.

The FPSC requires natural gas utilities to offer transportation-only service to all non-residential customers. As a result, PGS receives its base rate for distribution regardless of whether a customer decides to opt for transportation-only service or continue bundled service. PGS had over 11,000 transportation customers as of Dec. 31, 2004 out of 28,900 eligible customers.

8

Table of Contents

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 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 57 interconnections (gate stations) serving PGS’ operating divisions. In addition, PGS’ Jacksonville Division receives gas delivered by the South Georgia Natural Gas Company pipeline through two gate stations located northwest of Jacksonville. Gulfstream Natural Gas Pipeline initiated gas delivery in 2003 through four gate stations. The addition of the Gulfstream pipeline enhances reliability of service and helps meet the capacity needs for PGS’ growing customer base.

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 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.

9

Table of Contents

PGS’ franchise agreements with the incorporated municipalities within its service area have various expiration dates ranging from the present through 2032. PGS expects to negotiate 4 to 6 franchises in 2005, the majority of which will be renewals of existing agreements. Franchise fees payable by PGS, which totaled $8.6 million in 2004, 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 former manufactured gas plant sites. See the previous discussion in the Environmental Matters section of Tampa Electric – Electric Operations.

Expenditures

During the five years ended Dec. 31, 2004, PGS has not incurred any material capital expenditures to meet environmental requirements, nor are any anticipated for 2005 through 2009.

TECO COAL

Overview

TECO Coal Corporation, with offices located in Corbin, Kentucky, is a wholly-owned subsidiary of TECO Energy, Inc. and through its subsidiaries operates surface and underground mines as well as coal processing facilities in eastern Kentucky, Tennessee and southwestern Virginia.

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, Perry County Coal Corporation, Bear Branch Coal Company, and TECO Synfuel Operations, LLC. The TECO Coal subsidiaries own or control, by lease, mineral rights, and own or operate surface and underground mines, synthetic fuel production facilities and coal processing and loading facilities. TECO Coal produces, processes and sells bituminous, low sulfur coal of steam, industrial and metallurgical grades. TECO Coal currently operates 28 underground mines which employ the room and pillar mining method and 10 surface mines.

In 2004, TECO Coal subsidiaries sold 9.1 million tons of coal. All of this coal was sold to customers other than Tampa Electric. Of the total sold, 6.3 million tons were produced and processed into synthetic fuel.

History

In 1974, Tampa Electric purchased Cal-Glo Coal Company, which produced a low sulfur, low ash fusion coal with high energy content. This suited Tampa Electric’s combustion quality and environmental requirements. In 1982, TECO Coal Corporation was formed and Cal-Glo Coal Company was renamed as Gatliff Coal Company. Rich Mountain Coal Company was established in 1987 when leases were signed for properties in Campbell County, Tennessee.

1988 saw a marketing change in which Gatliff Coal Company began selling ferro-silicon and silicon grade coal products (see Glossary of Selected Mining Terms in this section). In addition, in that year, properties were also acquired in Pike County, Kentucky and Clintwood Elkhorn Mining Company was formed. Premier Elkhorn Coal Company and Pike Letcher Land Company were formed in 1991, when additional property was acquired in Pike and Letcher Counties, Kentucky.

In 1997, Bear Branch Coal Company secured key leases for property located in Perry County, Kentucky.

The newest mining company in the TECO Coal family is Perry County Coal Corporation, which was purchased in 2000 and is located in Perry, Knott and Leslie Counties, Kentucky.

In 2000, TECO Coal purchased synthetic fuel production facilities from Headwaters Technologies, Inc. TECO Synfuel, LLC was formed in 2003 to administer the production and sale of synfuel product at various TECO Coal subsidiaries.

In 2004, Premier Elkhorn Coal Company acquired properties and the Millard Preparation Facilities (currently idle) from AEP, Kentucky Coal, LLC located in Pike County, Kentucky.

10

Table of Contents

Mining Operations

TECO Coal, through its subsidiaries, currently has four mining complexes, all operating in Kentucky with a portion of Clintwood Elkhorn Mining Company operating in Virginia. A mining complex is defined as all mines that supply a single wash plant, except in the case of Clintwood Elkhorn Mining Company and Premier Elkhorn Coal Company, which provide production for two wash plants. These complexes blend, process and ship coal that is produced from one or more mines, with a single complex handling the coal production of as many as 17 individual underground or surface mines. TECO Coal uses two distinct extraction techniques: continuous underground mining and dozer and front-end loader surface mining (see Glossary of Selected Mining Terms in this section). The complexes have been developed at strategic locations in close proximity to the TECO Coal preparation plants and rail shipping facilities. Coal is transported from TECO Coal’s mining complexes to customers by means of railroad cars, trucks, barge or vessels, with rail shipments representing approximately 91% of 2004 coal shipments. The map that follows shows the locations of the four mining complexes and TECO Coal’s offices in Corbin, Kentucky.

Facilities

Coal mined by the operating companies of TECO Coal is processed and shipped from state-of-the-art facilities located at each of the operating companies, with Clintwood Elkhorn Mining Company and Premier Elkhorn Coal Company having two facilities. The Clintwood facilities are located at Biggs, Kentucky and Hurley, Virginia, and the Premier facilities are located at Myra, Kentucky and the just acquired (and presently idle) facility at Millard, Kentucky. The equipment at each facility is in good condition and regularly maintained by qualified personnel. In 2003, major renovations were completed at the Perry County Coal Corporation facility that enable the plant to meet the additional production requirements brought about by the opening of the Elkhorn 4 seam underground mine. The following table presents a summary of TECO Coal processing facilities:

Processing Facilities Summary

11

Table of Contents

Significant Activities

Significant activities commenced in 2004 included the following:

Perry County Coal

Premier Elkhorn Coal

Clintwood Elkhorn Mining

Mining Complexes

The following table presents a summary of annual production for each mining complex for each of the last three years.

Gatliff Coal Company

Located in Bell County, Kentucky, Gatliff Coal Company is supplied by one surface mine. Principal products at this location consist primarily of high-quality steam coal (see Glossary of Selected Mining Terms in this section) for utilities. Products from this operation are transported by trucking contractors. Rich Mountain Coal Company formerly operated as a contractor for Gatliff Coal Company’s Tennessee production which is currently in non-producing reclamation status. Gatliff Coal Company produced and sold 0.29 million tons of coal in 2004, leaving a reserve base of 9.8 million recoverable tons (see Glossary of Selected Mining Terms in this section).

12

Table of Contents

Clintwood Elkhorn Mining Company

Clintwood Elkhorn Mining Company has two facilities. One is located near Biggs, Kentucky in Pike County and is supplied by eight underground mines and three surface mines. Principal products at the Biggs, Kentucky location include high volatile metallurgical coals (see Glossary of Selected Mining Terms in this section). The second Clintwood Elkhorn Mining Company facility is located near Hurley, Virginia and is supplied by three underground mines and one surface mine. The Hurley, Virginia operation facility also supplies high-volatile metallurgical coal as well as steam coal products. Products from both locations are shipped domestically to customers in North America via Norfolk Southern Corporation and vessels via the Great Lakes. International customers receive their products via ocean vessels departing from Lamberts Point, Virginia. In total, Clintwood Elkhorn Mining Company produced 1.75 million tons of coal in 2004, leaving a reserve base of 37.8 million recoverable tons.

Premier Elkhorn Coal Company

Located near Myra, in Pike County, Kentucky, Premier Elkhorn Coal Company is supplied by production from thirteen underground mines and four surface mines. Principal products include high-quality steam coal for utilities, specialty stoker products for ferro-silicon and industrial customers, and PCI and metallurgical coal for the steel mills. Facilities include a state-of-the-art unit train load-out with 200 car siding capable of loading at 6,000 tons per hour as well as a single car siding. Products from this location are shipped domestically via CSXT Railroad and trucking contractors. Internationally, products are shipped via TECO Bulk Terminal, a subsidiary of TECO Transport, in Davant, Louisiana. All production is performed by Premier Elkhorn Coal Company although Pike Letcher Land Company controls by fee and lease all of the recoverable reserves. The acquisition of the Millard Preparation Facilities (which is presently idle) and 14,800 acres of property from AEP, Kentucky Coal, LLC was completed during 2004. Premier Elkhorn Coal Company produced 3.65 million tons of coal in 2004, leaving a reserve base of 56.6 million recoverable tons.

Perry County Coal Corporation

Located near Hazard, Kentucky in Perry County, Kentucky, Perry County Coal Corporation is supplied by four underground mines and one surface mine. Principal products include high-quality steam coal for utilities and industrial stoker coal. Facilities include an upgraded 1,350 ton per hour preparation plant and two unit train load-outs (see Glossary of Selected Mining Terms in this section), each capable of loading at 5,000 tons per hour. Products from this location are shipped domestically via CSXT Railroad and trucking contractors. All production is performed by Perry County Coal Corporation, although Bear Branch Coal Company controls by lease a substantial amount of the Hazard area reserves. Additionally, during 2004, Perry County Coal explored and identified major reserves in the Elkhorn #4 seam at a location southwest of the current Perry County Coal facilities; exploration is on-going for this project, only a small portion of which relates to newly identified reserves in the Elkhorn #4 seam. Perry County Coal Corporation produced 2.81 million tons of coal in 2004, leaving a reserve base of 94.8 million recoverable tons.

TECO Synfuel Operations, LLC

TECO Coal sold a 49.5% membership interest in its synthetic fuel production facilities in April 2003, and an additional 40.5% in June 2004 along with associated rights to a percentage of the benefits in the business which adjust from time to time. Allocation of the benefits varied in 2004 such that more than 90% of the benefits were to third parties. See the TECO Coal section of MD&A for a description of these transactions. The 6.3 million tons of synfuel produced in 2004 replaced some of TECO Coal’s conventional coal production in 2004. Sales of the fuel produced 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 Private Letter Rulings 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 and resolved any uncertainty related to the sale of its indirect interest in the production facilities.

The Section 29 tax credit is determined annually and is estimated to be $1.12 per million Btu in 2004, and was $1.10 per million Btu in 2003 and $1.09 per million Btu in 2002. This rate escalates with inflation but could be limited by domestic oil prices. The annual weighted average price of domestic oil for 2004 would have had to exceed $51.00 per barrel to have adversely impacted the credits allowed for 2004. If the oil price limitation is reached, the level of the tax credits starts to decrease. TECO Coal has engaged in hedging transactions to partially mitigate the risk to higher oil prices. TECO Coal recorded no Section 29 tax credits for 2004 associated with its remaining synthetic fuel membership interest because of TECO Energy’s anticipated tax position in 2004. This compares with credits of $66.0 million in 2003 and $107.3 million in 2002. See the TECO Coal and the Income Taxes sections of MD&A.

13

Table of Contents

Sales and Marketing

The marketing and sales force for the TECO Coal subsidiaries includes sales managers, distribution/transportation managers and administrative personnel. Primary customers are utilities, steel companies and industrial plants. TECO Coal subsidiaries sell coal under long-term agreements, which are generally classified as greater than 12 months, and on a spot basis, which is generally classified as less than 12 months (see Glossary of Selected Mining Terms in this section).

The terms of TECO Coal’s subsidiaries’ coal sales contracts result from bidding and negotiations with customers. Consequently, these contracts typically vary significantly in price, quantity, quality, length, and may contain terms and conditions that allow for periodic price reviews, price adjustment mechanisms, and recovery of governmental impositions, as well as provisions for force majeure, suspension, termination, effects of environmental legislation and assignment.

Distribution

TECO Coal subsidiaries transport coal from their mining complexes to customers by rail, barge, vessel and trucks. They employ transportation specialists who coordinate the development of acceptable shipping schedules with their customers, transportation providers and mining facilities.

Competition

Primary competitors of TECO Coal’s subsidiaries are other coal suppliers, many of which are located in Central Appalachia. Even though consolidation and bankruptcy have decreased the number of coal suppliers, the industry is still intensely competitive. 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.

Employees

As of Dec. 31, 2004, TECO Coal and its subsidiaries employed a total of 789 employees.

Regulations

Mine Safety and Health Act

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.

Black Lung Benefits

Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must make payment of federal black lung benefits to claimants who are current and former employees, certain survivors of a miner who dies from black lung disease, and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to Jul. 1, 1973. Historically, a small percentage of the miners currently seeking federal black lung benefits are awarded these benefits by the federal government. The trust fund is funded by an excise tax on coal production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, with neither amount to exceed 4.4% of the gross sales price.

In December 2000, the Department of Labor issued new amendments to the regulations implementing the federal black lung laws that, among other things, establish a presumption in favor of a claimant’s treating physician, limit a coal operator’s ability to introduce medical evidence, and redefine Coal Workers Pneumoconiosis to include chronic obstructive pulmonary disease. These changes in the regulations will increase the percentage of claims approved and the overall cost of Black Lung to coal operators. TECO Coal, with the help of its consulting actuaries, intends to continue aggressively monitoring claims very closely.

Workers’ Compensation

TECO Coal is liable for worker’s compensation benefits for traumatic injury and occupational exposure claims under state workers’ compensation laws. Workers compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment.

14

Table of Contents

Environmental Laws

Surface Mining Control and Reclamation Act

Coal mining operations are 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.

Clean Air Act/Clean Water Act

While conducting their mining operations, TECO Coal’s subsidiaries are subject to various federal, state and local air and water pollution standards. In 2004, TECO Coal spent approximately $1.7 million on environmental protection and reclamation programs. TECO Coal expects to spend a similar amount in 2005 on these programs.

CERCLA (Superfund)

The Comprehensive Environmental Response, Compensation, and Liability Act affects coal mining and hard rock operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under Superfund, joint and several liabilities may be imposed on waste generators, site owners or operators and others regardless of fault.

Under the EPA’s Toxic Release Inventory process, companies are required to report annually listed toxic materials that exceed defined quantities.

Glossary of Selected Mining Terms

Assigned reserves. Coal that has been committed by the coal company to operating mine shafts, mining equipment, and plant facilities, and all coal which has been leased by the company to others.

Bituminous coal. The most common type of coal, with moisture content less than 20% by weight and heating value of 10,500 to 14,000 Btu per pound. It is dense and black and often has well-defined bands of bright and dull material.

Btu. (British Thermal Unit). A measure of the energy required to raise the temperature of one pound of water one degree Fahrenheit.

Central Appalachia. Coal producing states and regions of eastern Kentucky, eastern Tennessee, western Virginia and southern West Virginia.

Coal seam. Coal deposits occur in layers. Each layer is called a “seam.”

Coal washing. The process of removing impurities, such as ash and sulfur-based compounds, from coal.

Compliance coal. Coal that, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btus, which is equivalent to .72% sulfur per pound of 12,000 Btu coal. Compliance coal requires no mixing with other coals or use of sulfur dioxide reduction technologies by generators of electricity to comply with the requirements of the federal Clean Air Act.

Continuous miner. A machine used in underground mining to cut coal from the seam and load it onto conveyors or into shuttle cars in a continuous operation.

Continuous mining. One of two major underground mining methods now used in the United States. This process utilizes a continuous miner. The continuous miner removes or “cuts” the coal from the seam. The loosened coal then falls on a conveyor for removal to a shuttle car or larger conveyor belt system.

Deep mine. An underground coal mine.

Dozer and Front-end loader mining. An open-cast method of mining that uses large bull dozers to remove overburden, which is used to backfill pits after coal removal.

Ferro-silicon. An alloy of iron and silicon used in the production of carbon steel.

Force Majeure. An event that may prevent the company from conducting its mining operations as a result of, in whole or in part,: Acts of God, wars, riots, fires, explosions, breakdowns or accidents; strikes, lockouts or other labor difficulties; lack or shortages of labor, materials, utilities, energy sources, compliance with governmental rules, regulations or other governmental requirements; any other like causes.

15

Table of Contents

High Vol Bituminous coal. Coal that has a fixed carbon content less than 69%, and a volatile matter greater than 31% with a minimum of 14,000 Btus per pound. Volatile matter refers to the impurities that become gaseous when heated to certain temperatures.

Highwall miner. An auger-like apparatus that drives parallel rectangular entries from the surface up to 1000 feet deep.

Industrial coal. Coal used by industrial steam boilers to produce electricity or process steam. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal.

Long term contracts. Contracts with terms of one year or longer.

Low ash fusion. Coal that, when burned, typically produces ash that has a melting point below 2450 degrees Fahrenheit.

Low Sulfur coal. Coal that, when burned, emits 1.6 pounds or less of sulfur dioxide per million Btus.

Metallurgical coal. The various grades of coal suitable for carbonization to make coke for steel manufacture. Also known as “met” coal, it possesses four important qualities: volatility, which affects coke yield; the level of impurities, which affects coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Met coal has a particularly high Btu, but low ash content.

Overburden. Layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction.

Overburden ratio. The amount of overburden, commonly stated in cubic yards, that must be removed to excavate one ton of coal.

Pillar. An area of coal left to support the overlying strata in a mine; sometimes left permanently to support surface structures.

Pneumoconiosis. A lung disease caused by long-continued inhalation of mineral or metallic dust.

Preparation plant. Usually located on a mine site, although one plant may serve several mines. A preparation plant is a facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal’s sulfur content.

Probable (Indicated) reserves. Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart; therefore, the degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.

Proven (Measured) reserves. Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well established.

Pulverized Coal Injection (PCI). A system whereby coal is pulverized and injected into blast furnaces in the production of steel and/or steel products.

Reclamation. The process of restoring land and the environment to their approximate original state following mining activities. The process commonly includes “recontouring” or reshaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers. Reclamation operations are usually underway before the mining of a particular site is completed. Reclamation is closely regulated by both state and federal law.

Recoverable reserves. The amount of proven and probable reserves that can actually be recovered from the reserve base taking into account all mining and preparation losses involved in producing a saleable product using existing methods and under current law.

Reserves. That part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination.

16

Table of Contents

Resource (Non-reserve Coal Deposit). A coal-bearing body that does not qualify as a commercially viable coal reserve. Resources may be classified as such by either limited property control, geologic limitations, insufficient exploration or other limitations. In the future, it is possible that portions of the resource could be re-classified as reserve if those limitations are removed or mitigated by: improving market conditions, additional property control, favorable results of exploration, advances in technology, etc.

Roof. The stratum of rock or other mineral above a coal seam; the overhead surface of a coal working place. Same as “top.”

Room and pillar mining. In the underground room and pillar method of mining, continuous mining machines cut three to nine entries into the coal bed and connect them by driving crosscuts, leaving a series of rectangular pillars, or columns of coal to help support the mine roof and control the flow of air. As mining advances, a grid-like pattern of entries and pillars is formed. Additional coal may be recovered from the pillars as this panel of coal is retreated.

Spot market. Sales of coal under an agreement for shipments over a period of one year or less.

Steam coal. Coal used by power plants and industrial steam boilers to produce electricity or process steam. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal.

Sulfur. One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide is produced as a gaseous by-product of coal combustion.

Sulfur content. Coal is commonly described by its sulfur content due to the importance of sulfur in environmental regulations. “Low sulfur” coal has a variety of definitions but typically is used to describe coal consisting of 1.0% or less sulfur. A majority of TECO Coal’s Central Appalachian reserves are of low sulfur grades.

Surface mine. A mine in which the coal lies near the surface and can be extracted by removing overburden.

Synthetic Fuel (Synfuel). A solid fuel that is produced by mixing coal and/or coal waste with various additives, causing a chemical change to occur within the original product.

Tipple. A structure that facilitates the loading of coal into rail cars.

Tons. A “short” or net ton is equal to 2,000 pounds. A “long” or British ton is 2,240 pounds; a “metric” ton is approximately 2,205 pounds. The short ton is the unit of measure referred to in this Form 10-K.

Unassigned reserves. Coal that has not been committed, and that would require new mineshafts, mining equipment, or plant facilities before operations could begin in the property.

Underground mine. Also known as a “deep” mine. Usually located several hundred feet below the earth’s surface, an underground mine’s coal is removed mechanically and transferred by shuttle car or conveyor to the surface.

Unit train. A train of a specified number of cars carrying only coal. A typical unit train can carry at least 10,000 tons of coal in a single shipment.

Utility coal. Coal used by power plants to produce electricity or process steam. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal.

17

Table of Contents

TECO TRANSPORT

TECO Transport directly or indirectly owns an interest in eight subsidiaries which transport, store and transfer coal and other dry-bulk commodities. These subsidiaries include TECO Ocean Shipping, Inc. (Ocean Shipping), TECO Barge Line, Inc. (TECO Barge), TECO Bulk Terminal, LLC (Bulk Terminal) and TECO Towing Company. TECO Transport currently owns no operating assets. TECO Transport and its subsidiaries had 901 employees as of Dec. 31, 2004.

TECO Transport’s subsidiaries perform substantial services for Tampa Electric. In 2004, approximately 31% of TECO Transport’s revenues were from Tampa Electric and approximately 69% were from third-party customers including phosphate customers, steel industry customers, grain customers, coal and petroleum coke customers, and participation in the U.S. Government’s cargo preference programs. The pricing for services performed by TECO Transport’s operating companies for Tampa Electric is based on a market-based 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 vessels (ships and barges) is for domestic and international movements of 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.

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 dry-bulk operator based on capacity, while TECO Barge is one of the ten largest companies in its business, based on number of barges. 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 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 who operate floating cranes or other floating discharge and loading equipment, 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 2004, all transportation services provided by TECO Transport’s subsidiaries were within this exemption.

During 2004, Ocean Shipping contributed an ocean barge to a joint venture for a 50% ownership interest valued at approximately $3 million and recorded an after-tax impairment of $0.3 million on the barge. Ocean shipping also recorded an additional $0.3 million after-tax impairment to adjust the fair value of other vessels.

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 2004, TECO Transport spent $0.2 million for environmental compliance. Environmental expenditures are estimated at $0.3 million in 2005, 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.

OTHER UNREGULATED COMPANIES

TWG Non-Merchant

TWG Non-Merchant, Inc. (Non-Merchant) has subsidiaries that have or had interests in independent power projects in Florida, Hawaii and Guatemala. Non-Merchant had 122 employees as of Dec. 31, 2004.

In October 2003, the partnership interest of Hardee Power Partners, Ltd. (HPP), a Florida limited partnership which wholly owned the 370-megawatt Hardee Power Station located in Hardee County, Florida, was sold. See Note 16 to the TECO Energy Consolidated Financial Statements for a description of the sale and its impact on the results of continuing operations. Under the terms of the sale, subsidiaries of Non-Merchant continued to provide services to HPP under the existing operation and maintenance agreement until Sep. 30, 2004. Additionally, Tampa Electric’s long-term power purchase obligation to receive electricity from HPP remains in effect with no changes as a result of the sale.

In July 2004, Non-Merchant’s 50% indirect interest in the Hamakua Power Station (Hamakua) in Hawaii was sold. See Note 16 to the TECO Energy Consolidated Financial Statements for a description of the sale.

Non-Merchant indirectly owns 100% of Central Generadora Eléctrica San José, Limitada (CGESJ), the owner of a project located in Guatemala, which consists of a single-unit pulverized-coal baseload facility (the San José Power Station). This facility was 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.

18

Table of Contents

(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 at the end of its current term for approximately $2.5 million. In 2002, CGESJ transferred the port assets to Tecnología Marítima, S.A. (TEMSA), a new indirect wholly-owned subsidiary. TEMSA, in addition to receiving the coal shipments for CGESJ, provides unloading services to third parties. Affiliates of Non-Merchant had originally obtained $114 million of limited recourse financing from Bank of America (BOA), Overseas Private Investment Corporation (OPIC) and Trust Company of the West (TCW) for the San José Power Station. In May 2004, CGESJ paid off its loans with BOA, OPIC and TCW with proceeds from a non-recourse $120 million loan from a syndication led by Banco Industrial, a local bank in Guatemala. Political risk insurance has been obtained for currency inconvertibility, expropriation and political violence covering up to 100% of Non-Merchant’s indirect equity investment and economic returns.

Tampa Centro Americana de Electricidad, Limitada (TCAE), an entity 96.06% owned by TPS Guatemala One, Inc., a subsidiary of Non-Merchant, and the owner of the Alborada Power Station, has 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 a subsidiary of Non-Merchant providing assistance in fuel administration. Affiliates of Non-Merchant 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 $25 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% of Non-Merchant’s indirect equity investment and economic returns.

In 1998, a consortium that includes affiliates of TECO Energy, Iberdrola, an electric utility in Spain, and Electricidade de Portugal, an electric utility in Portugal, completed the purchase of an 80% ownership interest in EEGSA for $520 million. The company indirectly owns a 24% interest in this consortium and contributed $100 million in equity. EEGSA serves more than 740,000 customers. EEGSA’s service territory includes the capital of Guatemala, Guatemala City. The consortium obtained limited-recourse debt financing for a portion of the purchase price. A subsidiary of Non-Merchant has obtained political risk insurance for currency inconvertibility, expropriation and political violence covering up to 100% of Non-Merchant’s indirect equity investment and economic returns.

As a result of the adoption of FIN 46R, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51, effective Jan. 1, 2004, CGESJ and TCAE were deconsolidated. See Note 2 to the TECO Energy Consolidated Financial Statements for additional information about the adoption of FIN 46R.

For financial information about geographic areas, see Note 14 to the TECO Energy Consolidated Financial Statements.

TECO Solutions

TECO Solutions was formed when it appeared that Florida was moving toward more competitive energy markets to offer customers (primarily in Florida) a comprehensive package of energy services and products. The subsequent move away from proposed deregulation and TECO Energy’s renewed focus on the core utility operations has caused the company to reexamine its participation in these lines of business. The result was the sale of several of the entities within TECO Solutions (see Note 16 to the TECO Energy Consolidated Financial Statements for detailed information about these sale transactions). Operating companies under TECO Solutions include TECO BCH Mechanical, TECO Gas Services Inc. and TECO Partners, Inc., with total employees of 505 as of Dec. 31, 2004.

TECO BCH Mechanical and its affiliated companies (BCH) provided air-conditioning, electrical and plumbing systems, and repair and maintenance services to institutional and commercial customers throughout Florida. On Jan. 7, 2005, TECO Solutions entered into an agreement to sell BCH Mechanical effective Dec. 31, 2004. BCH’s results of operations are accounted for as discontinued operations for all periods reported.

In 2003, TECO Solutions sold TECO Gas Services’ commercial and industrial book of business. TECO Gas Services will continue to provide services to their cogeneration customers. TECO Gas Services owns no operating assets.

Effective Jan. 1, 2004, TECO Solutions completed the sale of TECO BGA, Inc. (BGA), an engineering energy services company. BGA’s results are accounted for as discontinued operations for all periods reported.

Effective Feb. 1, 2004, TECO Solutions completed the sale of substantially all the assets of Prior Energy, a leading natural gas management company. Prior Energy’s results are accounted for as discontinued operations for all periods reported.

TECO Propane Ventures (TPV) held 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. In 2004, U.S. Propane completed the sale of its direct and indirect equity investments in Heritage Propane Partners, L.P. (Heritage). TPV owns no operating assets.

19

Table of Contents

TWG MERCHANT, INC.

TWG Merchant, Inc. (TWG-Merchant) has subsidiaries that have interests in independent power projects in Virginia, Mississippi, Arkansas, and Arizona. In 2003, TECO Energy announced that its strategy going forward was to focus on the Florida utilities and profitable unregulated businesses and to reduce the company’s exposure to the merchant power markets. Since that time, TECO Energy has continued the steps in implementing that strategy, including the sale of merchant power assets as discussed below in the Summary of Projects. TWG-Merchant had 182 employees as of Dec. 31, 2004.

As discussed above under TECO Energy, the TWG-Merchant operating segment is comprised of all continuing merchant operations, including the direct and indirect results from continuing operations of the independent power projects in Virginia, Mississippi and Arkansas, as well as the energy marketing operations for these plants, TECO EnergySource, Inc. (TES). Prior to its sale in December 2004, the results of operations for Frontera were included in TWG-Merchant. Also, prior to Dec. 31, 2003, the results of operations of Union and Gila River’s independent power projects in Arkansas and Arizona, respectively, (TPGC) were included in TWG-Merchant. These are now reported in discontinued operations. The results of TWG-Merchant’s investment in the Texas Independent Energy, L.P. (TIE) projects are also included in the TWG-Merchant segment.

Like Tampa Electric, the U.S. operations of TWG-Merchant 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.

See Note 14 to the TECO Energy Consolidated Financial Statements for specific details of the results of operations for the TWG-Merchant operating segment.

Summary of Projects

Union and Gila River Projects (TPGC)

In 2000, TWG Wholesale Generation, Inc. (TWG) announced a joint venture with Panda Energy International (Panda) to build, own and operate two natural gas power plants located in Arkansas and Arizona, respectively, known as the Union and Gila River projects. In February 2002, subsidiaries of TWG entered into an agreement requiring those subsidiaries to purchase 100% of Panda’s interest in the joint venture for $60 million in 2007, unless Panda chose to remain a partner by canceling the agreement and paying a cancellation fee. In April 2003, subsidiaries of TWG-Merchant and Panda agreed to amendments to this agreement which resulted in TWG-Merchant indirectly consolidating the joint venture (TPGC) at that time. In June 2003, subsidiaries of TWG-Merchant terminated Panda’s continued involvement in the partnership, resulting in the recognition of after-tax charges in the second quarter of 2003 of $155.9 million, as a direct result of the consolidation of TPGC (see Note 20 to the TECO Energy Consolidated Financial Statements).

In 2001, the project entities owned by TWG and Panda closed on a $2,175 million financing for the Union and Gila River power stations, including $1,675 million in five-year non-recourse debt and $500 million in equity bridge loans. The equity bridge loans were guaranteed by TECO Energy and were repaid in 2002 and 2003. As a result of events in October 2003 and December 2003 (see the TWG-Merchant. section of MD&A), and other economic factors impacting the general market conditions for independent power projects, TWG-Merchant recognized an after-tax asset impairment charge of $762.0 million ($1,185.7 million pretax) in 2003. In 2004, discussions with the steering committee of the lending group resulted in an agreement on all material terms and forms of definitive agreements for a sale and transfer of ownership of the project companies to the lending group. However, during the process of seeking the required 100% approval from the lenders, two lenders dissented. The lending group indicated that a pre-negotiated Chapter 11 bankruptcy for the project companies was likely to be required. In January 2005, the lending group approved a pre-negotiated Chapter 11 filing of the project companies in order to facilitate the completion of this transaction. No material changes in the terms of the transaction are anticipated, and the company expects to complete the transfer of TPGC in 2005. See also Notes 12, 20, 21 and 23 to the TECO Energy Consolidated Financial Statements for additional details of the results of operations for these project companies.

PLC Development/TIE

A TWG-Merchant subsidiary acquired an ownership interest in PLC on Jan. 2, 2003, as part of the TPGC joint venture termination, described above (see Note 13 to the TECO Energy Consolidated Financial Statements). TWG-Merchant’s foreclosure on an additional loan to a subsidiary of Panda resulted in TWG-Merchant obtaining an indirect effective economic interest of 50% in the aggregate of 2,000-megawatts in TIE. On Aug. 30, 2004, a TWG-Merchant subsidiary completed the sale of its 50% indirect interest in TIE. The company recorded a $152.3 million pretax impairment charge ($99.0 million after tax) to write off the value of the investment as a result of the sale (see Note 16 to the TECO Energy Consolidated Financial Statements).

20

Table of Contents

Dell and McAdams Projects

In 2000, TWG-Merchant acquired full ownership of two independent power projects, the Dell and McAdams projects, being developed in Arkansas and Mississippi, respectively, with combined capacity of the two plants to be nearly 1,200 megawatts. 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. As of Dec. 31, 2003, approximately $685 million had been invested in these plants. In December 2004, TWG-Merchant recorded an after-tax impairment charge of approximately $391 million related to these projects (see Note 18 to the TECO Energy Consolidated Financial Statements). At this time, TWG-Merchant has made the decision that these projects will probably not be completed.

Frontera Power Station

In March 2001, subsidiaries of TWG-Merchant acquired the Frontera Power Station, a 477-megawatt natural gas-fired combined-cycle plant located near McAllen, Texas. In December 2004, subsidiaries of TWG-Merchant sold its 100% interest in Frontera. As a result of the sale, an after-tax loss of approximately $27 million was recorded. (See also Notes 16 and 21 to the TECO Energy Consolidated Financial Statements for additional information.)

Commonwealth Chesapeake Power Station

TWG-Merchant, through TM Delmarva Power, LLC (TMDP), has a 100% economic interest in Commonwealth Chesapeake Power Station (CCC), a 315-megawatt power plant on the Delmarva Peninsula of Virginia. In 2003, an after-tax charge of $26.7 million was recognized to establish a reserve against an arbitration award against TMDP by NCP of Virginia, L.L.C. (NCP), which held a minority interest in CCC. In August 2004, TMDP entered into an agreement with NCP and its owners under which TMDP purchased NCP’s interest in CCC for $30 million in cash plus TECO Energy stock valued at $10 million. This transaction resulted in a positive after-tax impact on earnings of approximately $4.3 million. In December 2004, TWG-Merchant recorded an after-tax impairment charge of approximately $52 million related to CCC. On Jan. 13, 2005 TMDP entered into an agreement to sell its membership interests in CCC. The sale is expected to close near the end of the first quarter of 2005, subject to a financing contingency and certain regulatory approvals. (See also Notes 18 and 23 to the TECO Energy Consolidated Financial Statements for additional information.)

TM Power Ventures

In 1998, TM Power Ventures LLC (TMPV) was created by subsidiaries of TWG-Merchant 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. In 2002, TWG-Merchant purchased Mosbacher Power’s minority ownership interest in TMPV, thereby giving TWG-Merchant a 100% ownership interest in TMPV. In 2003, TMPV sold its interest in a repowered independent power project in the Czech Republic, receiving $33 million in cash.

Competition and Markets

The U.S. power plants that TWG-Merchant indirectly owns and operates and those for which construction has been suspended are located in markets with a history of high load growth. However, starting in late 2001 and early 2002, conditions in energy markets and the independent power business changed dramatically. Wholesale power prices declined significantly in markets across the country for many reasons, including a general slowing, or in some states, a reversal of the movement towards wholesale electric competition and the large amount of new generating capacity that came online in 2002 and 2003, which contributed to significant excess generating capacity in many areas of the country. Accordingly, TWG-Merchant ceased work on any new power plant developments, and has been active in its efforts to reduce its merchant exposure (see Strategy and Outlook section of MD&A).

As announced previously in April 2003, TECO Energy’s renewed focus is on core utility operations and profitable unregulated businesses. TECO Energy sought to increase its flexibility to be able to mitigate the risk from the merchant portfolio through a number of steps, including the termination of joint ventures with Panda Energy in the TPGC plants and in the TIE plants, and to exit from existing merchant projects. Significant steps were achieved in 2004 and 2003, as discussed above with respect to TWG-Merchant’s ownership exit plan from merchant activities.

See the discussion of the risks applicable to TWG-Merchant in the Investment Considerations section of MD&A.

21

Table of Contents

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 are subject to a first mortgage bond indenture under which no bonds are currently outstanding, and the properties of most of the subsidiaries of TECO Wholesale Generation are generally subject to liens securing long-term debt.

TAMPA ELECTRIC

At Dec. 31, 2004, Tampa Electric had five electric generating plants and five combustion turbine units in service with a total net winter generating capability of 4,421 megawatts, including Big Bend (1,759-MW capability from four coal units), Bayside (1,827-MW capability from two natural gas units), Phillips (34-MW capability from two diesel units), Polk (260-MW capability from one integrated gasification combined cycle (IGCC) unit), three combustion turbine units (CTs) located at Big Bend (175-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. 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 Big Bend went into service from 1970-1985. The Polk IGCC unit began commercial operation in 1996. In 1991, Tampa Electric purchased two power plants (Dinner Lake and Phillips) from the Sebring Utilities Commission (Sebring). Phillips was placed in service by Sebring in 1983. Dinner Lake was retired from service in January 2003.

The repowering of Gannon station to Bayside station was completed with the conversion of Gannon Unit 5 to Bayside Unit 1 in April 2003 and Gannon Unit 6 to Bayside Unit 2 in January 2004 (see the Environmental Compliance section of MD&A). Total capacity at Bayside has increased to 1,827 megawatts as a result of the operation of Bayside Unit 2. Gannon Units 1 and 2 were placed on long-term reserve standby (LTRS) in April 2003 and retired in January 2004. Gannon Units 3 and 4 were placed on LTRS in September 2003 and retired from coal operation in January 2004, after which the assets may be utilized for future gas operations. The agreement between Tampa Electric, EPA, and the FDEP required all coal burning at the Gannon Station to cease by the end of 2004, but allows the units to be repowered on natural gas.

Tampa Electric owns 188 substations having an aggregate transformer capacity of 20,416 Mega Volts Amps (MVA). The transmission system consists of approximately 1,304 pole miles (including underground and double-circuit) of high voltage transmission lines, and the distribution system consists of 7,053 pole miles of overhead lines and 3,323 trench miles of underground lines. As of Dec. 31, 2004, there were 625,850 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 the 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 15,700 miles of pipe, including approximately 9,900 miles of mains and over 5,800 miles of service lines. Mains and service lines are maintained under rights-of-way, franchises or permits.

PGS’ operating divisions are located in 14 markets throughout Florida. While most of the operations and administrative facilities are owned, a small number are leased.

22

Table of Contents

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 17 towboats and 632 river barges, approximately 81% of which it owns, on the Mississippi, Ohio and Illinois rivers and their tributaries. 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, 2004, TECO Ocean Shipping owns or operates a fleet of 8 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 335,000 tons.

TECO COAL

Property Control

Operations of TECO Coal and its subsidiaries are conducted on both owned and leased properties totaling more than 221,000 acres in Kentucky, Tennessee and Virginia. TECO Coal’s current practice is to obtain a title review from a licensed attorney prior to purchasing or leasing property, and it has not obtained title insurance in connection with its acquisitions of coal reserves and/or related surface properties. In many cases, the seller or lessor will grant the purchasing or leasing entity a warranty of property title. When leasing coal reserves and/or related surface properties where mining has previously occurred, TECO Coal may opt not to perform a separate title confirmation due to the previous mining activities on such a property. In cases involving less significant properties, and consistent with industry practices, title and boundaries are not completely verified until such time as TECO Coal’s subsidiaries prepare to disturb or mine such properties.

In situations where property is controlled by lease, the lease terms are generally sufficient to allow the reserves for the associated operation to be mined within the initial lease term. In fact the terms of many of these leases extend until the exhaustion of the mineable and merchantable coal from the leased property. If, however, extensions of the original lease term become necessary, provisions have generally been made within the original lease to extend the lease term upon continued payment of minimum royalties.

Coal Reserves

As of Dec. 31, 2004, the TECO Coal operating companies have a combined estimated 199 million tons of proven and probable recoverable reserves. All of the reserves consist of High Vol A Bituminous Coal. Reserves are the portion of the proven and probable tonnage that meet TECO Coal’s economic criteria regarding mining height, preparation plant recovery, depth of overburden and stripping ratio. Generally, these reserves would be commercially mineable at year-end price and cost levels. Additionally, 35.5 million tons of coal classified as “resource” were identified in the third-party audit report.

Reserves are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves, as defined by SEC Industry Guide 7, are included in the Glossary of Selected Mining Terms in the Business – TECO Coal section.

Drill hole spacing for confidence levels in reserve calculations is based on guidelines in U.S. Geological Survey Circular 891 (Coal Resource Classification System of the U.S. Geological Survey). In this method of classification, “proven” reserves are considered to be those lying within one-quarter mile (1,320 feet) of a valid point of measurement and “probable” reserves are those lying between one-quarter mile and three-quarters mile (3,960 feet) from such an observation point.

TECO Coal reserve estimates are prepared by TECO Coal’s staff of geologists, whose experience range from 15 years to 30 years. TECO Coal also has two chief geologists with the responsibility to track changes in reserve estimates, supervise TECO Coal’s other geologists and coordinate third-party reviews of TECO Coal’s reserve estimates by qualified mining consultants. In 2004, a third-party audit of TECO Coal’s reserves was performed. The results of that audit are reflected in the numbers within this report.

The following table presents a summary of recoverable reserves by quantity and the method of property control as well as the Assigned and Unassigned reserves per mining complex.

23

Table of Contents

Recoverable Reserves By Quantity ⁽¹⁾

(Million of tons)

The following table presents a summary of recoverable reserves by quality, including sulfur content and coal type, per mining complex.

Recoverable Reserves By Quality ⁽¹⁾

Reserve Estimation Procedure

TECO Coal’s reserves are based on over 2500 data points, including drill holes, prospect measurements, and mine measurements. Our reserve estimates also include information obtained from our on-going exploration drilling and in-mine channel sampling programs. 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. Additionally, the information is constantly being updated to reflect new data for existing property as well as new acquisitions and depleted reserves.

This data may include elevation, thickness, and, where samples are available, the quality of the coal from individual drill holes and channel samples. The information is assembled by qualified geologists and engineers located throughout TECO Coal. Information is entered into sophisticated computer modeling programs from which preliminary reserves estimations are generated. The information derived from the geological database is then combined with data on ownership or control of the mineral and surface interests to determine the extent of the reserves in a given area. Determinations of reserves are made after in-house geologists have reviewed the computer models and adjusted the grids to better reflect regional trends.

During its reserve evaluation and mine planning, TECO Coal takes into account factors such as restrictions under railroads, roads, buildings, power lines, or other structures. Depending on these factors, coal recovery may be limited or, in

24

Table of Contents

some instances, entirely prohibited. Current engineering practices are used to determine potential subsidence zones. The footprint of the relevant structure as well as a safety angle-of-draw are considered when mining near or under such facilities. Also, as part of TECO Coal’s reserve and mineability evaluation, TECO Coal reviews legal, economic and other technical factors. Final review and recoverable reserve determination is completed after a thorough analysis by in-house engineers, geologists and finance associates.

OTHER UNREGULATED COMPANIES

TPS Guatemala One, Inc. has a 96.06% interest in TCAE, which owns 7 acres in Escuintla, Guatemala on which the 78 MW oil-fired Alborada Power Station is located. TPS San José, LDC has a 100% ownership in a project entity, CGESJ, which owns 190 acres in Masagua, Guatemala on which the 120 MW coal-fired San José Power Station is located.

TWG-MERCHANT

TWG-Merchant indirectly holds a 100% ownership interest in Union Power Partners, LP, Panda Gila River, LP, and Trans-Union Interstate Pipeline, LP. Union Power Partners owns 330 acres of land in Union County, Arkansas, on which the 2,200 MW gas-fired combined-cycle Union electric generation plant is located. Panda Gila River, LP owns approximately 1,099 acres of land in Maricopa County, Arizona, on which the 2,145-megawatt gas-fired combined-cycle Gila River electric generation plant is located. Trans-Union owns an interstate pipeline associated with the Union facility. See the TWG-Merchant section of MD&A for a discussion of the expected transfer of the ownership of these projects.

TM Delmarva Power, LLC has a 100% ownership 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. Completion of the announced sale of Commonwealth Chesapeake Company, LLC is expected by the end of the first quarter of 2005.

TPS Dell, LLC owns approximately 100 acres in the City of Dell in Mississippi County, Arkansas, on which the partially constructed 599-megawatt gas-fired combined-cycle Dell electric generation plant is located. TPS McAdams, LLC, owns approximately 210 acres of land in McAdams and Sallis in Attala County, Mississippi, on which the partially constructed 599-megawatt gas-fired combined cycle McAdams electric generation plant is located. 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.

25

Table of Contents

Item 3. LEGAL PROCEEDINGS.

Grupo Lawsuit

In March 2001, TWG (under its former name of TECO Power Services Corporation) was served with a lawsuit filed in the Circuit Court for Hillsborough County by a Tampa-based firm named Grupo Interamerica, LLC. (“Grupo”) in connection with a potential investment in a power project in Colombia in 1996. Grupo alleged, among other things, that TWG breached an oral contract with Grupo. On Aug. 3, 2004, the trial court granted TWG’s motion for summary judgment, resulting in only one count remaining. On Oct. 18, 2004, TWG’s motion for summary judgment on the remaining count was granted. The plaintiffs have appealed and the company expects that the appellate court would render a decision by the end of 2005.

On Aug. 30, 2004, a Colombian trade union, Sindicato de Trabajadores de la Electricidad de Colombia, which was to be the owner/lessor of the power plant if the transaction had been consummated, filed a demand for arbitration in Colombia pursuant to provisions of a confidentiality and exclusivity agreement (the “confidentiality agreement”) between the trade union and a subsidiary of TWG, TPS International Power, Inc., alleging breach of contract and seeking damages of $48 million. TECO Energy, Inc. and TWG also were named, although those companies were not parties to the confidentiality agreement. This arbitration is being funded by Grupo pursuant to a contract under which Grupo would share in any recovery. The arbitration is in its preliminary stages, and, although the respondents have not been served, the parties’ arbitrators have been selected by the parties.

Other Issues

A number of securities class action lawsuits were filed in August, September and October 2004 against the company and certain current and former officers by purchasers of TECO Energy securities. These suits, which were filed in the U.S. District Court for the Middle District of Florida, allege disclosure violations under the Securities Exchange Act of 1934. These actions were consolidated and remain in the initial pleading stage as of Dec. 31, 2004. On Feb. 1, 2005, the court entered its order appointing the lead plaintiff, comprising NECA-IBEW Pension Fund (The Decatur Plan), Monroe County Employees Retirement System, John Marder and Charles Korpak, and also the lead counsel. The plaintiffs have until Apr. 4, 2005) to file a consolidated complaint. The company intends to defend the litigation vigorously. In addition, in connection with the SEC informal inquiry resulting from a letter from the non-equity member in the Commonwealth Chesapeake Project raising issues related to the arbitration proceeding involving that project, which previously was disclosed in the company’s Quarterly Report on Form 10-Q for the quarter ended Mar. 31, 2004, the SEC has requested additional information primarily relating to the allegations made in these securities class action lawsuits and focusing on various merchant plant investments and related matters.

The company cannot predict the ultimate resolution of these matters, including the class action litigation and the Grupo-related proceedings, at this time, and there can be no assurance that any such matters will not have a material adverse impact on TECO Energy’s financial condition or results of operations.

See also the discussions of the outcome of the coal transportation contract hearing before the FPSC in the Regulation – Coal Transportation Contract Section of MD&A, Notes 3 and 13 to the TECO Energy Consolidated Financial Statements and Notes 3 and 10 to the Tampa Electric Company Consolidated Financial Statements, and also the discussion of environmental matters in Note 12 to the TECO Energy Consolidated Financial Statements and Note 9 to the Tampa Electric Company Consolidated Financial Statements.

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

No matter was submitted during the fourth quarter of 2004 to a vote of TECO Energy’s security holders, through the solicitation of proxies or otherwise.

26

Table of Contents

EXECUTIVE OFFICERS OF THE REGISTRANT

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

There is no family relationship between any of the persons named above. The term of office of each officer extends to the meeting of the Board of Directors following the next annual meeting of shareholders, scheduled to be held on Apr. 27, 2005, and until such officer’s successor is elected and qualified.

27

Table of Contents

PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The following table shows the high and low sale prices for shares of TECO Energy common stock, which is listed on the New York Stock Exchange, and dividends paid per share, per quarter.

The approximate number of shareholders of record of common stock of TECO Energy as of Feb. 28, 2005 was 20,544.

Dividends on TECO Energy’s common stock are declared and paid at the discretion of its Board of Directors. The primary sources of funds to pay dividends to its common shareholders are dividends and other distributions from its operating companies. TECO Energy’s $380 million note indenture contains a covenant that requires the company to achieve certain interest coverage levels in order to pay dividends. TECO Energy’s $200 million credit facility contains a covenant that could limit the payment of dividends exceeding $50 million in any quarter under certain circumstances. Certain long-term debt at PGS contains restrictions that limit the payment of dividends and distributions on the common stock of Tampa Electric. Tampa Electric’s $125 million credit facility, which included a covenant limiting cumulative distributions and outstanding affiliate loans, was amended in 2004 resulting in the elimination of this covenant.

In addition, TECO Diversified, Inc., a wholly-owned subsidiary of TECO Energy and the holding company for TECO Transport, TECO Coal and TECO Solutions, has a guarantee related to a coal supply agreement that limits the payment of dividends to its common shareholder, TECO Energy, but does not limit loans or advances.

See Liquidity, Capital Resources – Covenants in Financing Agreements section of MD&A, and Notes 6, 7 and 12 to the TECO Energy Consolidated Financial Statements for a more detailed description of significant financial covenants.

TECO Energy holds the right to defer payments on its subordinated notes issued in connection with the issuances of trust preferred securities by TECO Capital Trust I or TECO Capital Trust II. Should the company exercise this right, it 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.

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 $163.2 million in 2004, $151.4 million in 2003 and $197.4 million in 2002. See the Restrictions on Dividend Payments and Transfer of Assets section in Note 1 to the TECO Energy Consolidated Financial Statements for Tampa Electric Company for a description of restrictions on dividends on its common stock.

28

Table of Contents

Set forth below is a table showing shares of TECO Energy common stock deemed repurchased by the issuer.

Item 6. SELECTED FINANCIAL DATA OF TECO ENERGY, INC.

29

Table of Contents

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. Actual results may differ materially from those forecasted. These forward-looking statements include references to TECO Energy’s anticipated capital investments, liquidity and financing requirements, projected operating results, future transactions and other plans. Certain factors that could cause actual results to differ materially from those projected in these forward-looking statements include: general economic conditions in Tampa Electric’s and Peoples Gas’ service areas affecting energy and gas sales; economic conditions, both national and international, affecting the demand for TECO Transport’s waterborne transportation services; state or federal regulatory actions that could reduce revenues or increase costs at all of TECO Energy’s operating companies; weather variations affecting energy and gas sales and operating costs at Tampa Electric and Peoples Gas and the effect of extreme weather conditions; commodity price changes affecting the margins at TECO Coal; and the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures. Additional factors that could impact actual results include: the ability to complete the planned transfer of the Union and Gila River power stations to the lending group in the time frame anticipated; the ability to complete the sale of the Commonwealth Chesapeake Power Station; any debt extinguishment costs or premiums associated with the early retirement of TECO Energy debt; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; declines in the anticipated waterborne fuel volumes transported by TECO Transport for Tampa Electric; TECO Coal’s ability to successfully operate its synthetic fuel production facilities in a manner qualifying for Section 29 federal income tax credits, which could be impacted by changes in law, regulation or administration; and materially adverse outcomes in the disclosed litigation. Some of these factors and others are discussed more fully under “Investment Considerations.”

TECO Energy, Inc. is a holding company, and all of its business is conducted through its subsidiaries. In this Management’s Discussion and Analysis, “we,” “our,” “ours” and “us” refer to TECO Energy, Inc. and its consolidated group of companies, unless the context otherwise requires.

OVERVIEW

Our actions in 2004 were driven by the implementation of the strategy announced in April 2003, which is to focus on our regulated utility operations in the high-growth Florida markets and our other profitable unregulated businesses and to reduce our exposure to the merchant power sector. A major component of this effort was an agreement to exit our ownership of the Union and Gila River power stations and to transfer the ownership of these power stations, which are part of the TECO Wholesale Generation (TWG) segment of TECO Energy that has been involved heretofore in merchant power activities. The exit strategy, which was announced in February 2004, is to transfer the ownership of these power stations to the lending group.

The continued generally poor financial performance at our other merchant power plants contributed to additional actions completed in 2004 that further reduced our exposure to the merchant power markets. (Merchant power plants are power plants that are not part of regulated utility operations, operate in the wholesale power market, and do not have long term contracts for the majority of their output. Most of the power from a merchant power plant is sold under short term agreements or in the more volatile wholesale power spot markets.) These actions included the sale of our 50% ownership interest in Texas Independent Energy (TIE), owner of two power plants in Texas; the sale of our 100% ownership interest in the Frontera Power Station in Texas; and the announcement in January 2005 of an agreement to sell the Commonwealth Chesapeake Power Station in Virginia. We experienced losses and value impairments on these sales and anticipated sales. In addition, we recognized an impairment of the value of the unfinished Dell and McAdams power stations, which there is a high probability we will no longer complete, to reflect the current market value for these plants. In 2004, we also sold the remaining major businesses in TECO Solutions, our small engineering and energy services unit, which operated in Florida as an adjunct to Peoples Gas. Some were sold at a gain and some at a loss. The components of TECO Solutions were acquired four or five years ago when it appeared that the Florida energy market would become more competitive.

With the commercial operation of the second phase of Tampa Electric’s H.L. Culbreath Bayside Power Station (Bayside) in January 2004, we completed the major power generation construction programs at Tampa Electric and TWG. With the construction programs complete, in 2004 we were able to build strong liquidity for normal operations and to begin accumulating the cash to position us to pay off all or the majority of our debt maturities in 2007.

For more than three months beginning in mid-August, Tampa Electric, Peoples Gas and TECO Transport were focused on either preparing for or recovering from the succession of major hurricanes that impacted Florida and surrounding states. Tampa Electric’s service area was directly impacted by three of the storms, each of which caused varying degrees of damage to its facilities and widespread customer outages. TECO Transport suffered no significant facility or equipment damage; however, its operations were disrupted by all four storms (see the Tampa Electric and TECO Transport sections).

Our financial results in 2004 were driven by the write-offs and valuation adjustments taken in the course of the year to eliminate the future risk to earnings and cash flow from the merchant power sector (see the Results Summary and TWG-Merchant sections).

30

Table of Contents

The operations of the five core businesses, Tampa Electric, Peoples Gas, TECO Coal, TECO Transport and the Guatemalan operations, were fundamentally sound in 2004. While TECO Transport experienced difficult market and operating conditions in the course of the year, these five companies produced good operating results. (See the individual operating companies for a detailed discussion of their respective results.)

RESULTS SUMMARY

Our financial results for 2004 reflect the write-offs resulting from the sales of our merchant generating assets and asset valuation adjustments associated with the remaining unfinished merchant power plants. The net loss in 2004 was $552.0 million, primarily due to $555.6 million of charges and gains detailed in the 2004 Non-operating Items Affecting Net Income table. The net loss from continuing operations in 2004 was $404.4 million, compared with net income from continuing operations of $61.7 million in 2003. Non-GAAP (Generally Accepted Accounting Principles) results from continuing operations excluding the charges and gains detailed in the 2004 Non-operating Items Affecting Net Income table were $151.2 million in 2004, compared with $176.3 million in 2003. Results from discontinued operations in 2004 reflect primarily the operating results from the Frontera, Union and Gila River power stations, BCH Mechanical, and the 2004 write-offs and charges associated with these businesses.

The sale of our interests in our merchant generating assets in Texas, the announced sale of Commonwealth Chesapeake Power Station in Virginia, and the adjustment of the value of the unfinished Dell and McAdams power stations to reflect the current fair market value resulted in $562.5 million of after-tax write-offs in 2004, comprised of $482.6 million in continuing operations and $79.9 million in discontinued operations.

Results from continuing operations in 2004 were lower than 2003, primarily due to the write-offs associated with the merchant power plants and other charges detailed in the 2004 Non-operating Items Affecting Net Income table. Excluding these charges and gains, results from continuing operations were lower due to the sale of an additional 40.5% membership interest in TECO Coal’s synthetic fuel production facilities, much lower equity Allowance for Funds Used During Construction income (AFUDC, which represents allowed equity cost capitalized to construction costs) at Tampa Electric, and lower results at TECO Transport. The sale of the portion of the synthetic fuel production facilities is and will continue to generate significant cash, but earnings at a lower level, due to our continued role in operating the synthetic fuel production facilities at a time when TECO Energy cannot utilize the Section 29 tax credits. The net loss on a per share basis was $2.87 in 2004, compared with net loss of $5.05 in 2003. The loss from continuing operations on a per share basis was $2.10 in 2004, compared with earnings per share from continuing operations of $0.34 in 2003. The number of average shares outstanding at Dec. 31, 2004 was 7% higher than at Dec. 31, 2003 primarily due to the shares issued in the early settlement offer for our equity security units completed in August.

In 2003, results from continuing operations were lower than in 2002, primarily due to charges associated with the impairment of some of our merchant power assets, charges for corporate restructuring and staffing reductions, valuation adjustments at the energy services companies and limitations on the use of tax credits (see the table 2003 Non-operating Items Affecting Net Income). Excluding these charges and gains, results from continuing operations were lower due to higher depreciation and interest expense at Tampa Electric; continued weak results at TECO Transport due to lower coal tonnage for Tampa Electric and continued weakness in the river business; higher interest expense at the TECO Energy parent level associated with the debt incurred to fund the TWG projects; lower results from TWG’s interest in the TIE projects in Texas; and the elimination of interest and support income from Panda Energy related to the TIE projects. These results were partially offset by the gain on the sale of Hardee Power Partners, higher operating results at TECO Coal from increased synthetic fuel production and sales, and the sale of the 49.5% membership interest in the synthetic fuel production facilities. The net loss on a per-share basis was $5.05 in 2003, compared with earnings of $2.15 per share in 2002. Earnings per share from continuing operations were $0.34 in 2003, compared with earnings per share from continuing operations of $1.75 in 2002. The average number of shares outstanding at Dec. 31, 2003 was more than 17% higher than at Dec. 31, 2002.

31

Table of Contents

2004 Earnings Summary