Form 10-K
Table of Contents

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

 

x Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

For the fiscal year ended December 31, 2003

 

OR

 

¨ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

For the transition period from                      to                     

 

Commission

File No.


 

Exact name of each Registrant as specified in its
charter, state of incorporation, address of
principal executive offices, telephone number


 

I.R.S. Employer

Identification

Number


1-8180   TECO ENERGY, INC.   59-2052286
   

(a Florida corporation)

TECO Plaza

702 N. Franklin Street

Tampa, Florida 33602

(813) 228-4111

   
1-5007   TAMPA ELECTRIC COMPANY   59-0475140
   

(a Florida corporation)

TECO Plaza

702 N. Franklin Street

Tampa, Florida 33602

(813) 228-4111

   

 

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

 

Title of each class


 

Name of each exchange on

which registered


TECO Energy, Inc.    
Common Stock, $1.00 par value   New York Stock Exchange
Common Stock Purchase Rights   New York Stock Exchange
Equity Security Units   New York Stock Exchange

 

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

 

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

YES x NO ¨

 

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

 

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

YES x NO ¨

 

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

YES ¨ NO x

 

The aggregate market value of TECO Energy, Inc.’s common stock held by nonaffiliates of the registrant as of June 30, 2003 was $2,117,879,345.

 

The aggregate market value of Tampa Electric Company’s common stock held by nonaffiliates of the registrant as of June 30, 2003 was zero.

 

The number of shares of TECO Energy, Inc.’s common stock outstanding as of February 29, 2004 was 188,175,926. As of February 29, 2004, 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 TECO Energy, Inc.’s 2003 Annual Report are incorporated by reference into Parts II and IV.

 

Portions of the Definitive Proxy Statement relating to the 2004 Annual Meeting of Shareholders of TECO Energy, Inc. are incorporated by reference into Part III.

 

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

 

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

 

Page 1 of 67

Index to Exhibits begins on page 62

 



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 5,753 employees as of Dec. 31, 2003.

 

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 shareholder 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 web site.

 

TECO Energy currently owns no operating assets but holds all of the common stock of Tampa Electric Company and directly, or through its subsidiary TECO Diversified, Inc., the other subsidiaries listed below. 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 are identified below.

 

Tampa Electric Company, a Florida corporation and TECO Energy’s largest subsidiary, through its Tampa Electric division (Tampa Electric) provides retail electric service to more than 612,000 customers in West Central Florida with a net system generating capability of 3,256 megawatts (MW). On Jan. 15, 2004, Tampa Electric commissioned Bayside 2 (rated at 1,022 MW) for a combined capacity of 4,278 MW. Peoples Gas System (PGS), a division of Tampa Electric Company, is engaged in the purchase, distribution and marketing of natural gas for residential, commercial, industrial and electric power generation customers in Florida. With more than 299,000 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 2003 was 1.2 billion therms.

 

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

 

TECO Coal Corporation, a Kentucky corporation, owns no operating assets but owns all of the common stock of nine 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 Wholesale Generation, Inc. (TWG) (formerly TECO Power Services Corporation), a Florida corporation, has subsidiaries that have interests in independent power projects in Florida, Virginia, Hawaii, Arkansas, Mississippi, Texas, Arizona and Guatemala, and has investments in unconsolidated affiliates that participate in independent power projects and electric distribution in other parts of the United States (U.S.) and Guatemala. As part of its renewed focus on core utility operations, TECO Energy revised its internal reporting information used for evaluating, measuring and making decisions with respect to the components which previously comprised the TECO Power Services (TPS) operating segment. The revised operating segment, TWG Merchant, is comprised of all merchant operations which include the results of operations for the Frontera, Commonwealth Chesapeake, Dell and McAdams power plants, as well as the equity investment in other U.S. plants, and TECO EnergySource, Inc. (TES), the energy marketing operation for the merchant plants. The non-merchant assets that were formerly reported with TPS include the company’s interests in Florida, Hawaii and Guatemala and are now reported with Other Unregulated Companies.

 

TECO Energy’s other unregulated companies with continuing operations include the non-merchant operations of TECO Wholesale Generation as described above, TECO Solutions, Inc. (TECO Solutions), TECO Properties, Inc. (TECO Properties), and TECO Investments, Inc. The TECO Solutions’ subsidiaries provide mechanical contracting, air conditioning, electrical and plumbing systems and repair and maintenance services in Florida.

 

Revenues for TECO Energy’s significant business segments for the years indicated follow. For additional financial information regarding TECO Energy’s significant business segments, see Note 19 to the TECO Energy Consolidated Financial Statements.

 

Revenues from Continuing Operations

 

(millions)


   2003

    2002

    2001

 

Tampa Electric

   $ 1,586.1     $ 1,583.2     $ 1,412.7  

Peoples Gas System

     408.4       318.1       352.9  
    


 


 


Total regulated businesses

     1,994.5       1,901.3       1,765.6  

TECO Wholesale Generation

     95.9       111.1       81.8  

TECO Transport

     260.6       254.6       274.9  

TECO Coal

     296.3       317.1       303.5  

Other unregulated businesses

     263.5       297.7       298.8  
    


 


 


       2,910.8       2,881.8       2,724.6  

Other and eliminations

     (170.8 )     (216.9 )     (241.3 )
    


 


 


     $ 2,740.0     $ 2,664.9     $ 2,483.3  
    


 


 


 

TWG’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, 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

 


Table of Contents

purchase and sale or other agreement, and expects to complete the transaction in 2004. TPGC’s results are accounted for as discontinued operations for all periods reported. Revenues from the discontinued operations of TPGC in 2003 were $319.4 million.

 

TECO Energy’s other unregulated companies completed several dispositions in 2003 and 2002, including the sale of Hardee Power Partners, Ltd. (HPP) in 2003 (part of the non-merchant operations of TWG) and the sale of TECO Coalbed Methane in 2002. Additionally in 2003, TECO Energy was committed to a plan to sell Prior Energy and TECO BGA (formerly a component of TECO Energy Services) as of Dec. 31, 2003. These sales were completed in early 2004. (See Note 23 to the TECO Energy Consolidated Financial Statements.) The company also completed the sale of substantially all of the net assets of TECO Gas Services in 2003. Results for TECO Coalbed Methane, Prior Energy and TECO Gas Services 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 $21.6 million, $51.5 million and $60.1 million for the years ended Dec. 31, 2003, 2002 and 2001, respectively.

 

TAMPA ELECTRIC—Electric Operations

 

Tampa Electric Company was incorporated in Florida in 1899 and was reincorporated in 1949. Tampa Electric Company is a public utility operating within the state of Florida. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy. The retail territory served comprises an area of about 2,000 square miles in West Central Florida, including Hillsborough County and parts of Polk, Pasco and Pinellas Counties, and has an estimated population of over one million. The principal communities served are Tampa, Winter Haven, Plant City and Dade City. In addition, Tampa Electric engages in wholesale sales to utilities and other resellers of electricity. It has 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 2,434 employees as of Dec. 31, 2003, of which 905 were represented by the International Brotherhood of Electrical Workers and 250 were represented by the Office and Professional Employees International Union.

 

In 2003, approximately 48 percent of Tampa Electric’s total operating revenue was derived from residential sales, 29 percent from commercial sales, 10 percent from industrial sales and 13 percent from other sales, including bulk power sales for resale. The sources of operating revenue and megawatt-hour sales for the years indicated were as follows:

 

Operating Revenue

 

(millions)


   2003

   2002

   2001

Residential

   $ 767.4    $ 753.9    $ 659.8

Commercial

     460.1      459.6      409.7

Industrial – Phosphate

     65.3      74.3      57.0

Industrial – Other

     88.5      83.8      71.8

Other retail sales of electricity

     124.9      117.4      103.0
    

  

  

Total retail

     1,506.2      1,489.0      1,301.3

Sales for resale

     41.6      67.7      82.4

Other

     38.3      26.5      29.0
    

  

  

     $ 1,586.1    $ 1,583.2    $ 1,412.7
    

  

  

 

Megawatt-hour Sales

 

(millions)


   2003

   2002

   2001

Residential

   8,265    8,046    7,594

Commercial

   5,860    5,832    5,685

Industrial

   2,579    2,612    2,329

Other retail sales of electricity

   1,538    1,435    1,368
    
  
  

Total retail

   18,242    17,925    16,976

Sales for resale

   691    1,084    1,499
    
  
  

Total energy sold

   18,933    19,009    18,475
    
  
  

 

No significant part of Tampa Electric’s business is dependent upon a single customer or a few customers, the loss of any one or more of whom would have a significant adverse effect on Tampa Electric. IMC-Agrico, a large phosphate producer, is Tampa Electric’s largest customer and represents less than 3 percent of Tampa Electric’s 2003 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.

 

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Regulation

 

The retail operations of Tampa Electric are regulated by the Florida Public Service Commission (FPSC), which has jurisdiction over retail rates, quality of service and reliability, issuances of securities, planning, siting and construction of facilities, accounting and depreciation practices, and other matters.

 

In general, the FPSC’s pricing objective is to set rates at a level that allows the utility to collect total revenues (revenue requirements) equal to its cost of providing service, plus a reasonable return on invested capital.

 

The costs of owning, operating and maintaining the utility system, other than fuel, purchased power, conservation and certain environmental costs, are recovered through base rates. These costs include operation and maintenance expenses, depreciation and taxes, as well as a return on Tampa Electric’s investment in assets used and useful in providing electric service (rate base). The rate of return on rate base, which is intended to approximate Tampa Electric’s weighted cost of capital, primarily includes its costs for debt, deferred income taxes at a zero cost rate and an allowed return on common equity. Base rates are determined in FPSC rate setting hearings which occur at irregular intervals at the initiative of Tampa Electric, the FPSC or other parties. See the discussion of the FPSC-approved agreements covering 1995 through 1999 in the Regulation – Tampa Electric Rate Strategy section of Management’s Discussion & Analysis of Financial Condition & Results of Operations (MD&A).

 

Tampa Electric’s rates and allowed return on equity (ROE) range of 10.75 percent to 12.75 percent with a midpoint of 11.75 percent are in effect until such time as changes are occasioned by an agreement approved by the FPSC or other FPSC actions as a result of rate or other proceedings initiated by Tampa Electric, FPSC staff or other interested parties. Tampa Electric expects to continue earning within its allowed ROE range without a base rate increase, even with the rate base additions associated with the repowering of the Bayside Power Station.

 

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 2003, 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 2004. In November, the FPSC approved Tampa Electric’s requested changes except for the lower coal transportation rate driven by a new contract with TECO Transport described below. The resulting rates include the impacts of the increased use of natural gas at the Bayside Power Station and the collection of $91 million for under-recovery of fuel expense for 2002 and 2003. The filing also included estimated waterborne transportation rates for coal transportation services. The FPSC did not allow the recovery of $8.4 million it characterized as savings from shutting down the Gannon Station earlier than originally planned which the FPSC deemed generated operations and maintenance savings. Tampa Electric filed its objection to the disallowance of the recovery of the $8.4 million and a motion asking FPSC to reconsider its decision because all facts and law were not taken into account. The motion was filed on Jan. 6, 2004, and a decision on this matter is expected in the first quarter of 2004. See Regulation – Cost Recovery Clauses section of MD&A.

 

Tampa Electric is also subject to regulation by the Federal Energy Regulatory Commission (FERC) in various respects, including wholesale power sales, certain wholesale power purchases, transmission services, and accounting and depreciation practices. See the Regulation – Transmission Rates and Regional Transmission Organization (RTO) sections of MD&A.

 

Federal, state and local environmental laws and regulations cover air quality, water quality, land use, power plant, substation and transmission line siting, noise and aesthetics, solid waste and other environmental matters. See Environmental Matters on pages 7 and 8.

 

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. TECO Transport sells transportation services to Tampa Electric and other third parties. Tampa Electric’s contract for coal transportation and storage services with TECO Transport expired on Dec. 31, 2003. In June 2003, Tampa Electric issued a Request For Proposal (RFP) to potential providers requesting services for the next five years. The results of the RFP process was the execution of a new contract between Tampa Electric and TECO Transport, effective Jan. 1, 2004, with market rates supported by the results of the RFP and an independent expert in maritime transportation matters. The prudence of the RFP process and final contract scheduled to be reviewed by the FPSC in the course of the normal fuel cost recovery hearings in November was deferred due to protests from other parties seeking more time to evaluate the contract information. The matter is scheduled to be heard by the FPSC in May with a decision expected in July. In the meantime, Tampa Electric is recovering fuel transportation costs at the rates from the

 

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now expired contract, which are slightly higher than those in the contract effective Jan. 1, 2004. See the Regulation – Coal Transportation Contract section of MD&A. Except for transportation services performed by TECO Transport under the U.S. bulk cargo preference program, the prices charged by TECO Transport to third-party customers are not subject to regulatory oversight.

 

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 market-based sales tariff for Tampa Electric, which allows Tampa Electric to sell excess power at market prices within Florida. The FERC had already approved market-based prices for interstate sales for Tampa Electric and the other investor-owned utilities (IOUs) operating in the state; however, Tampa Electric is the only IOU in the state with intrastate market-based sales authority.

 

There is presently 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. See Regulation – Transmission Rates section of MD&A.

 

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 the region that chose to join. In March 2001, the FERC conditionally approved GridFlorida. 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 a non-transmission owning RTO model. 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 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. The FPSC has scheduled a series of collaborative meetings with all interested parties and, upon their conclusion, will set items for hearing and a hearing schedule. This is expected to occur throughout 2004.

 

Fuel

 

Approximately 78 percent of Tampa Electric’s generation of electricity for 2003 was coal-fired, with natural gas representing approximately 21 percent and oil representing approximately 1 percent. Tampa Electric used its generating units to meet approximately 81 percent of the system load requirements, with the remaining 19 percent coming from purchased power. A lower level of coal generation as a percentage of total generation is anticipated for 2004 as a result of Gannon’s repowering to the natural gas fueled Bayside Power Station.

 

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

 

Average cost per million Btu:


   2003

   2002

   2001

   2000

   1999

Coal

   $ 2.02    $ 1.93    $ 2.06    $ 1.92    $ 2.00

Oil

   $ 6.42    $ 5.33    $ 5.79    $ 5.33    $ 3.09

Gas (Natural)

   $ 6.45    $ 5.86    $ 4.84    $ 5.49      —  

Composite

   $ 2.83    $ 2.11    $ 2.19    $ 2.07    $ 2.03

Average cost per ton of coal burned

   $ 48.32    $ 45.04    $ 47.53    $ 44.36    $ 44.63

 

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 used approximately 5.7 million tons of coal during 2003 and estimates that its fuel consumption will be about 5.0 million tons for 2004. During 2003, Tampa Electric purchased approximately 76 percent of its coal under long-term contracts with seven suppliers, and approximately 24 percent of its coal and petroleum coke in the spot market. Tampa Electric expects to obtain approximately 70 percent of its coal requirements in 2004 under long-term contracts with six suppliers and the remaining 30 percent in the spot market. The temporary change in the balance of long-term versus spot contracts is due to declining coal needs at Gannon Station in connection with the repowering to the Bayside Power Station. Tampa Electric’s remaining long-term contracts provide for revisions in the base price to reflect changes in a wide range of cost factors and for suspension or reduction of deliveries if environmental regulations should prevent Tampa Electric from burning the coal supplied, provided that a good faith effort has been made to continue burning such coal. For information concerning transportation services by affiliated companies to Tampa Electric, see the TECO Transport section of Business.

 

In 2003, approximately 56 percent of Tampa Electric’s coal supply was deep-mined, approximately 37 percent was surface-mined and the remainder was a processed oil by-product known as petroleum coke. Federal surface-mining laws and regulations have not had any material adverse impact on Tampa Electric’s coal supply or results of its operations. Tampa Electric, however, cannot predict the effect of any future mining laws and regulations.

 

Natural Gas. In 2003, Tampa Electric contracted for 80 percent of winter 2003-2004 expected gas needs and 40 percent for the 2004 summer period. In the spring of 2004, Tampa Electric expects to contract for an additional 20-40 percent of the 2004 summer and 40 percent of the winter 2004-2005 requirements. Additional volumes are expected to be procured on the short-term spot market.

 

Oil. Tampa Electric is in the process of finalizing supply agreements for No. 2 fuel oil for its Polk and Big Bend Stations at prices based on Gulf Coast Cargo spot indices. No. 6 fuel oil is purchased on the spot market for its Phillips Station.

 

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, except for the cities of Tampa and Winter Haven, have reserved the right to purchase Tampa Electric’s property used in the exercise of its franchise if the franchise is not renewed; otherwise, based on judicial precedent, Tampa Electric is able to keep its facilities in place subject to reasonable rules and regulations imposed by the municipalities.

 

Tampa Electric has franchise agreements with 13 incorporated municipalities within its retail service area. These agreements have various expiration dates ranging from November 2005 to March 2021.

 

Franchise fees payable by Tampa Electric, which totaled $27.6 million in 2003, are calculated using a formula based primarily on electric revenues and are collected on customers’ bills.

 

Utility operations in Hillsborough, Pasco, Pinellas and Polk Counties outside of incorporated municipalities are conducted in each case under one or more permits to use state or county rights-of-way granted by the Florida Department of Transportation or the county commissioners of such counties. There is no law limiting the time for which such permits may be granted by counties. There are no fixed expiration dates for the Hillsborough County and Pinellas County agreements. The agreements covering electric operations in Polk and Pasco counties expire in 2004 and 2023, respectively. Tampa Electric expects to reach a renewal agreement for the Polk agreement.

 

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Environmental Matters

 

Consent Decree

 

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

 

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

 

Emission Reductions

 

Since 1998, Tampa Electric has reduced annual SO2, NOx, and particulate matter (PM) emissions from its facilities by 129,430 tons, 27,630 tons, and 2,865 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. Currently, the scrubbers at Big Bend Station remove more than 95 percent of the SO2 emissions from the flue gas streams.

 

In addition, the Consent Decree and Consent Final Judgment related projects will result in significant reductions in emissions. Reductions have already resulted from the completion of the repowering of Gannon Station to Bayside Power Station in April 2003 (Bayside Unit 1) and January 2004 (Bayside Unit 2). Should Tampa Electric decide to continue to burn coal, the installation of additional NOx 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 SO2 by 156,501 tons per year, NOx by 61,549 tons per year, and PM by 3,626 tons per year from 1998 levels. In total, Tampa Electric’s emission reduction initiatives will result in the reduction of SO2, NOx and PM emissions by 90 percent, 89 percent, and 70 percent, respectively, below 1998 levels. With these improvements in place, Tampa Electric’s facilities will meet the same standards required of new power generating facilities and help to significantly enhance the quality of the air in the community.

 

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 44 percent below 1998 levels, there are virtually zero mercury emissions. Additional mercury reductions are also anticipated from the installation of NOx controls at Big Bend Station, which would lead to a mercury removal efficiency of approximately 70 percent. Depending on the NOx control technology selected for Big Bend, the mercury reductions may vary and lead to lower than anticipated mercury removal efficiencies.

 

The repowering of Gannon Station to Bayside Station will also lead to a significant reduction in carbon dioxide (CO2) emissions. It is expected that by 2005, the repowering will bring an approximate 5.2 million ton decrease in CO2 emissions below 1998 levels. This reduction will result in the Tampa Electric system CO2 emissions being 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 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, 2003, Tampa Electric Company has estimated its ultimate financial liability to be approximately $20 million, and this amount has been reflected in the consolidated financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

 

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

 

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

 

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

 

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Capital Expenditures

 

During the five years ended Dec. 31, 2003, Tampa Electric spent $116.4 million, excluding the Gannon repowering, on capital additions to meet environmental requirements. A significant portion of the $83 million project for the Big Bend Units 1 and 2 scrubbers is included in the five-year total. A new scrubber system was installed at Big Bend Units 1 and 2 to meet Phase 2 S02 emission reduction requirements under the Clean Air Act Amendments of 1990.

 

In total, Tampa Electric spent an estimated $11.7 million in 2003 on environmental projects. Environmental expenditures are estimated at $18.2 million for 2004 and an additional $324 million in total for 2005 through 2008. These totals include the expenditures required to comply with the EPA Consent Decree, which are discussed below.

 

In 2003, Tampa Electric spent approximately $3.6 million for compliance with the EPA consent decree requirements at Big Bend station for reduction of NOx and PM emissions and to improve the scrubber systems to reduce S02 emissions. Should Tampa Electric choose to continue to burn coal at Big Bend station, further NOx emission reductions would require expenditures in 2004 estimated at $3.7 million and as much as $221 million being spent during 2005 through 2008. Estimated expenditures for the continued improvement of electrostatic precipitators for PM emissions reductions will be $1.5 million in 2004 and an additional $6.5 million during 2005 through 2008. Tampa Electric has also spent $658 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.

 

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 299,000 customers. The system includes approximately 9,500 miles of mains and over 5,500 miles of service lines. (See PGS’ Franchise section of Business.)

 

In 2003, the total throughput for PGS was 1.2 billion therms. Of this total throughput, 13 percent was gas purchased and resold to retail customers by PGS, 72 percent was third party supplied gas delivered for retail transportation only customers, and 15 percent was gas sold off-system. Industrial and power generation customers consumed approximately 65 percent of PGS’ annual therm volume, commercial customers used approximately 30 percent and the balance was consumed by residential customers.

 

While the residential market represents only a small percentage of total therm volume, residential operations generally comprise 25 percent of total revenues. New residential construction including natural gas and conversions of existing residences to gas have steadily increased since the late 1980’s.

 

Natural gas has historically been used in many traditional industrial and commercial operations throughout Florida, including production of products such as steel, glass, ceramic tile and food products. 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:

 

     Revenues

   Therms

(millions)


   2003

   2002

   2001

   2003

   2002

   2001

Residential

   $ 105.6    $ 76.6    $ 88.2    64.2    60.2    58.8

Commercial

     143.6      122.3      163.6    354.8    327.6    308.9

Industrial

     114.8      80.3      50.7    406.2    423.8    346.5

Power Generation

     10.1      11.4      11.3    363.7    492.6    403.5

Other revenues

     34.0      27.5      39.1    —      —      —  
    

  

  

  
  
  

Total

   $ 408.4    $ 318.1    $ 352.9    1,188.9    1,304.2    1,117.7
    

  

  

  
  
  

 

PGS had 565 employees as of Dec. 31, 2003. A total of 94 employees in six of PGS’ 15 operating divisions are represented by various union organizations.

 

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Regulation

 

The operations of PGS are regulated by the FPSC separate from the regulation of Tampa Electric’s electric operations. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows a utility such as PGS to collect total revenues (revenue requirements) equal to its cost of providing service, plus a reasonable return on invested capital.

 

The basic costs of providing natural gas service, other than the costs of purchased gas and interstate pipeline capacity, are recovered through base rates. Base rates are designed to recover the costs of owning, operating and maintaining the utility system. The rate of return on rate base, which is intended to approximate PGS’ weighted cost of capital, primarily includes its cost for debt, deferred income taxes at a zero cost rate, and an allowed return on common equity. Base rates are determined in FPSC proceedings which occur at irregular intervals at the initiative of PGS, the FPSC or other parties. For a description of recent proceeding activity, see the Regulation – Peoples Gas 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 (PGA) clause. This charge is designed to recover the costs incurred by PGS for purchased gas, and for holding and using interstate pipeline capacity for the transportation of gas it sells to its customers. These charges are adjusted monthly based on a cap approved annually in an FPSC hearing. The cap is based on estimated costs of purchased gas and pipeline capacity, and estimated customer usage for a specific recovery period, with a true-up adjustment to reflect the variance of actual costs and usage from the projected charges for prior periods. For a description of the most recent adjustment, see the Regulation – Cost Recovery Clauses – 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 consumed to recover the costs incurred by PGS in developing and implementing energy conservation programs, which are mandated by Florida law and approved and supervised by the FPSC. PGS is permitted to recover, on a dollar-for-dollar basis, expenditures made in connection with these programs if it demonstrates that the programs are cost effective for its ratepayers.

 

In February 2000, the FPSC approved a rule that required natural gas utilities to offer transportation-only service to all non-residential customers. The net result of the unbundling is a shift from commodity sales to transportation sales. PGS continues to receive its base rate for distribution regardless of whether a customer decided to opt for transportation-only service or continue bundled service. PGS had over 10,500 transportation customers as of Dec. 31, 2003.

 

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 55 interconnections (gate stations) serving PGS’ operating divisions. In addition, PGS’ Jacksonville Division receives gas delivered by the South Georgia Natural Gas Company (South Georgia) pipeline through two gate stations located northwest of Jacksonville.

 

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In 2003, Gulfstream Natural Gas Pipeline initiated gas delivery through four new gate stations. PGS entered into a service agreement for capacity in 2002, which increases in 2003 and 2004. The addition of the Gulfstream pipeline enhances reliability of service and helps 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 include the cities of Lakeland, Jacksonville, Daytona Beach, Eustis, Fort Myers, Ocala, Brooksville, Orlando, Tampa, St. Petersburg, Sarasota, Avon Park, Frostproof, Palm Beach Gardens, Pompano Beach, Fort Lauderdale, Hollywood, North Miami, Miami Beach, Miami, and Panama City. These franchises give PGS a right to occupy municipal rights-of-way within the franchise area. The franchises are irrevocable and are not subject to amendment without the consent of PGS, although in certain events, they are subject to forfeiture.

 

Municipalities are prohibited from granting any franchise for a term exceeding 30 years. Several franchises contain purchase options with respect to the purchase of PGS’ property located in the franchise area, if the franchise is not renewed; otherwise, based on judicial precedent, PGS is able to keep its facilities in place subject to reasonable rules and regulations imposed by the municipalities.

 

PGS’ franchise agreements with the incorporated municipalities within its service area have various expiration dates ranging from the present through July 2031. PGS has two franchises in negotiations for 2004. One is a renewal and the second is a new franchise. Franchise fees payable by PGS, which totaled $8.0 million in 2003, are calculated using various formulas which are based principally on natural gas revenues. Franchise fees are collected from only those customers within each franchise area.

 

Utility operations in areas outside of incorporated municipalities are conducted in each case under one or more permits to use state or county rights-of-way granted by the Florida Department of Transportation or the county commissioners of such counties. There is no law limiting the time for which such permits may be granted by counties. There are no fixed expiration dates and these rights are, therefore, considered perpetual.

 

Environmental Matters

 

PGS’ operations are subject to federal, state and local statutes, rules and regulations relating to the discharge of materials into the environment and the protection of the environment generally that require monitoring, permitting and ongoing expenditures.

 

Tampa Electric Company is one of several potentially responsible parties for certain superfund sites and, through PGS, for certain superfund and former manufactured gas plant sites. See the previous discussion in the Environmental Matters section of Tampa Electric – Electric Operations on pages 6 and 7.

 

Expenditures. During the five years ended Dec. 31, 2003, PGS has not incurred any material capital expenditures to meet environmental requirements, nor are any anticipated for 2004 through 2008.

 

TECO WHOLESALE GENERATION (FORMERLY TECO POWER SERVICES)

 

TECO Wholesale Generation, Inc. (TWG) has subsidiaries that have interests in independent power projects in Florida, Virginia, Hawaii, Mississippi, Arkansas, Texas, Arizona and Guatemala. TWG had 352 employees as of Dec. 31, 2003.

 

As discussed under the TECO Energy section of Business, the TWG 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, Arkansas and Texas, as well as the energy marketing operation for these plants, TECO EnergySource, Inc. (TES). 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; however, these are now reported in discontinued operations. Included in the Other Unregulated companies operating segment are the results of operations of the non-merchant independent power projects in Florida, Hawaii and Guatemala (i.e., those with long-term power projects).

 

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Like Tampa Electric, the U.S. operations of TWG 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 19 to the TECO Energy Consolidated Financial Statements for specific details of the results of operations for the TWG Merchant operating segment and the non-merchant power component of the Other Unregulated Companies segment described below.

 

TWG Merchant Operating Segment

 

In 1998, TM Power Ventures LLC (TMPV) was created by TWG and Mosbacher Power Partners, Ltd. (Mosbacher Power), an independent power company headquartered in Houston, to jointly develop, own and operate domestic and international independent power projects. Under this arrangement, TWG provided capital and technical expertise to TMPV. In 1998, TWG, through TMPV, made certain loans to Mosbacher Power. Also in 1998, TWG, through TMPV, acquired approximately a 13 percent interest in a re-powered independent power project in the Czech Republic (the ECKG project). The facility completed its expansion to a total of 344 megawatts in the first quarter of 2000. In 2002, TWG purchased Mosbacher Power’s minority ownership interest in TMPV, thereby giving TWG a 100-percent ownership interest in TMPV. As part of the purchase, TWG received principal and interest due on its loans to Mosbacher Power. Also in 2002, TWG recorded a $5.8 million after-tax charge to adjust the valuation of the investment in the ECKG project in connection with the proposed sale of that investment. In 2003, TMPV sold its interest in the ECKG project. As a result of the sale, TMPV received for $33 million in cash.

 

TWG, through TMPV, has a 100-percent economic interest in Commonwealth Chesapeake Power Station (CCC), a 315-megawatt power plant on the Delmarva Peninsula of Virginia. The first phase of 134 megawatts went into service in the third quarter of 2000, and the second phase went into service in August 2001. In 2003, an after-tax charge of $26.7 million was recognized to establish a reserve against an arbitration award against TMDP, the indirect owner of CCC.

 

In the first quarter of 2001, TWG sold its minority interest in EGI, a Bermuda-based energy development firm. As part of the sale, TWG took an after-tax charge of $6.1 million ($9.3 million pre-tax) to adjust the asset valuation of the investment.

 

In September 2000, TWG provided a $93 million investment in the form of a loan related to Panda Energy International’s (Panda) Texas Independent Energy projects (TIE). In February 2002, TWG provided an additional investment in the form of a loan in the amount of $44 million. These loans converted in accordance with their terms into an ownership interest on Jan. 3, 2003. Subsequently, in 2003, as part of the TPGC joint venture termination, described below, TWG foreclosed on an additional loan to a subsidiary of Panda Energy for $23 million. This foreclosure resulted in TWG obtaining an indirect effective economic interest of 50 percent in the aggregate of 2,000-megawatts in TIE. The two TIE projects, known as Guadalupe and Odessa, are located in Texas and operate as gas-fired, combined-cycle units. The projects were brought on line in phases beginning in December 2000, with all the capacity in service in August 2001.

 

In October 2000, TWG acquired from Genpower LLC full ownership of two independent power projects being developed in Arkansas and Mississippi with combined capacity of the two plants to be nearly 1,200 megawatts. The two 599-megawatt facilities, known as the Dell and McAdams projects, were designed to be natural gas-fired combined-cycle plants. Construction on these plants was suspended at the end of 2002 due to low energy prices in the markets that these plants were expected to serve. Market conditions will be monitored to determine when these plans will be completed. As of Dec. 31, 2003, approximately $690 million had been invested in these plants and TWG estimates that the construction cost to complete these projects would be approximately $100 million. (See the TECO Wholesale Generation, Inc. – Merchant Generation Facilities section of MD&A.)

 

In November 2000, TWG announced a joint venture with Panda to build, own and operate two natural gas power plants located in Arkansas and Arizona, known as the Union and Gila River projects. The first phase of the Union power plant began commercial operations in January 2003, and the entire facility was commercially operational in the second quarter of 2003. Union sells power primarily to utilities and industrial customers in Arkansas, Louisiana, eastern Texas and Mississippi. The first phase of the other project, in Gila Bend, Arizona, began commercial operations in the second quarter of 2003 and the entire facility was commercially operational in the third quarter of 2003. Electricity from Gila River is primarily sold in Arizona, Nevada and New Mexico. In February 2002, subsidiaries of TWG entered into an agreement requiring those subsidiaries to purchase 100 percent 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 and Panda agreed to amendments to this agreement which resulted in TWG indirectly consolidating the joint venture (TPGC) at that time. (See the Transactions with Related and Certain Other Parties section of MD&A.) In June 2003, subsidiaries of TWG 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.

 

In June 2001, the project entities owned by TWG and Panda closed on a bank financing for the Union and Gila River power stations. This $2.175 billion bank financing included $1.675 billion in five-year non-recourse debt and $500 million in equity bridge loans guaranteed by TECO Energy. The equity bridge loans were repaid in 2002 and 2003. As a result of events in October 2003 and December 2003 (see the TECO Wholesale Generation, Inc. section of MD&A), and other economic factors impacting the general market conditions for independent power projects, TWG recognized a pre-tax asset impairment charge of $1,185.7 million in 2003. Subsequent to Dec. 31, 2003, discussions with the bank financing group have resulted in a non-binding letter of intent that would allow for an exit from the ownership of these project companies. (See also Notes 10, 12, 20 and 23 to the TECO Energy Consolidated Financial Statements for additional details of the results of operations for these project companies.)

 

In March 2001, subsidiaries of TWG acquired American Electric Power’s (AEP) Frontera Power Station, located near McAllen, Texas. Frontera is a 477-megawatt natural gas-fired combined-cycle plant. Frontera is capable of selling power domestically, as well as into the Mexican power market, through a direct interconnection with the Comisíon Federal de Electricidad, the Mexican power authority.

 

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Other Unregulated Companies Operating Segment

 

Hardee Power Partners, Ltd. (HPP) is a Florida limited partnership which wholly owns the Hardee Power Station, a 370-megawatt combined cycle electric generating facility located in Hardee County, Florida, which began commercial operation in 1993. Until recently, HPP was an indirect wholly-owned subsidiary of TWG. In 1993, HPP began to fulfill 20-year power supply agreements for all the capacity and energy of the Hardee Power Station, with Tampa Electric and Seminole Electric Cooperative (Seminole Electric), a Florida electric cooperative that provides wholesale power to ten electric distribution cooperatives. Under the Seminole Electric agreements, HPP agreed to supply Seminole Electric with an additional 145 megawatts of capacity during the first ten years of the contract, which ended on Dec. 31, 2002. This additional capacity was purchased from Tampa Electric’s coal-fired Big Bend Unit Four for resale to Seminole Electric. The 75-megawatt capacity expansion completed at Hardee Power Station in May 2000 is expected to serve Tampa Electric through 2012. The expansion consists of a General Electric combustion turbine operating in simple-cycle mode. In 2003, the company sold the partnership interests of HPP to a third party. (See Note 21 to the TECO Energy Consolidated Financial Statements for a description of the sale and its impact on the results of continuing operations.) The sale did not impact the long-term power supply agreements with Tampa Electric or Seminole Electric.

 

As part of its non-merchant operations, TWG is a 50-percent indirect owner in the Hamakua Energy Project, a 60-megawatt combined cycle cogeneration facility in Hamakua, Hawaii. The facility was constructed and placed into service during 2000. A subsidiary of TWG jointly owns and operates the project under a 30-year power purchase agreement with Hawaii Electric Light Company. The interests of the previous joint owner, J.A. Jones Ventures, were auctioned to a third party in early 2004.

 

As part of its non-merchant operations, TWG indirectly owns 100 percent of Central Generadora Eléctrica San Jose, Limitada (CGESJ), the owner of a project located in Guatemala, which consists of a single-unit pulverized-coal baseload facility (the San Jose 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. (EEGSA), a private distribution and generation company, to provide 120 megawatts of capacity for 15 years beginning in 2000. In 2001, CGESJ signed an option with EEGSA to extend that PPA for five years for approximately $2.5 million. In 2002, CGESJ began to transfer the port assets to Tecnología Marítima, S.A. (TEMSA), a new indirect wholly-owned subsidiary. This transaction was completed in the first quarter of 2003. TEMSA, in addition to receiving the coal shipments for CGESJ, provides unloading services to third parties. Political risk insurance has been obtained for currency inconvertibility, expropriation and political violence covering up to 100 percent of TWG’s indirect equity investment and economic returns.

 

Tampa Centro Americana de Electricidad, Limitada (TCAE), an entity 96.06-percent owned by TPS Guatemala One, Inc., a subsidiary of TWG and the owners of the Alborada Power Station, have a U.S. dollar-denominated PPA with EEGSA to provide 78 megawatts of capacity for a 15-year period ending in 2010. In 2001, TCAE signed an option with EEGSA to extend that PPA for five years at the end of its current term for approximately $2.9 million. EEGSA is responsible for providing the fuel for the plant, with a subsidiary of TWG providing assistance in fuel administration. Affiliates of TWG had originally obtained $29 million of limited recourse financing from the Overseas Private Investment Corporation (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 percent of TWG’s indirect equity investment and economic returns.

 

EEGSA serves more than 717,000 customers. EEGSA’s service territory includes the capital of Guatemala, Guatemala City. In 1998, a consortium that includes affiliates of the company, Iberdrola, an electric utility in Spain, and Electricidade de Portugal, an electric utility in Portugal, completed the purchase of an 80-percent ownership interest in EEGSA for $520 million. The company indirectly owns a 24 percent interest in this consortium and contributed $100 million in equity. The consortium obtained limited-recourse debt financing for a portion of the purchase price. A subsidiary of TWG has obtained political risk insurance for currency inconvertibility, expropriation and political violence covering up to 100 percent of TWG’s indirect equity investment and economic returns.

 

Competition and Markets

 

The U.S. power plants that TWG indirectly owns and operates and those for which construction has been suspended are located in markets with a history of high load growth. However, the general U.S. economic slowdown over the past several years has slowed the growth in demand for power in some of these markets. In addition, the slowdown of electricity deregulation initiatives across the United States, including the markets that these facilities serve, caused in part by the failure of deregulation in California and other events, has allowed the traditional, incumbent utilities to continue to operate older, less efficient generating facilities in lieu of purchasing power from newer, more efficient independent power plants. These factors have combined with aggressive plans by the independent power industry to add merchant power facilities to cause excess generating capacity that is either being built or has come on line in many markets. This excess supply has depressed both spot and forward prices. Accordingly, TWG has ceased work on any new power plant developments, and is active in its efforts to reduce its merchant exposure.

 

TECO Energy’s renewed focus is on core utility operations. In April 2003, TECO Energy announced that the company would seek 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. These terminations were accomplished in 2003. In October 2003, the company announced that little, if any, additional cash would be invested into the merchant generation portfolio. Significant steps have been achieved in 2003 with respect to TWG’s ownership exit plan for the Union and Gila River project companies. See the TWG – Energy Markets section of MD&A for additional discussion of competition and the merchant energy markets.

 

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See the discussion of the risks applicable to TWG in the Investment Considerations section of MD&A. For financial information about geographic areas, see Note 19 to the TECO Energy Consolidated Financial Statements.

 

TECO TRANSPORT

 

TECO Transport owns all of the common stock of four subsidiaries which transport, store and transfer coal and other dry-bulk commodities. These subsidiaries include TECO Ocean Shipping, Inc. (Ocean Shipping), 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 914 employees as of Dec. 31, 2003.

 

TECO Transport’s subsidiaries perform substantial services for Tampa Electric. In 2003, approximately 62 percent of TECO Transport’s revenues were from third-party customers and approximately 38 percent were from Tampa Electric. 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 barges is for domestic and international movements of other dry-bulk commodities and domestic phosphate movements. Both the terminal and river transport operations handle a variety of dry-bulk commodities for third party customers.

 

A substantial portion of TECO Transport’s business is dependent upon Tampa Electric, phosphate customers, steel industry customers, grain customers, coal and petroleum coke customers, and participation in the U.S. Government’s cargo preference programs.

 

Ocean Shipping transports products in the Gulf of Mexico and worldwide, and TECO Barge operates on the Mississippi, Ohio and Illinois rivers and their tributaries. Their primary competitors are other barge and shipping lines and railroads, as well as a number of other companies offering transportation services on the waterways used by TECO Transport’s subsidiaries. Ocean Shipping is the largest US flag coastwise dry bulk operator based on capacity, while TECO Barge is in the top ten, based on number of barges, of companies in its business. To date, physical and technological improvements have allowed ship and barge operators to maintain competitive rate structures with alternate methods of transporting bulk commodities when the origin and destination of such shipments are contiguous to navigable waterways.

 

Bulk Terminal operates the largest transfer and storage terminal on the Gulf coast. Demand for the use of such terminals is dependent upon customers’ use of water transportation versus alternate means of moving bulk commodities and the demand for these commodities. Competition consists primarily of mid-stream operators and other land-based terminals.

 

Competition within TECO Transport’s markets is based primarily on geographic markets served, pricing, and service level. The majority of the ocean and all of the river business is subject to the Jones Act, which prohibits the use of non-US flag vessels for movement between US ports.

 

The business of TECO Transport’s subsidiaries, taken as a whole, is not subject to significant seasonal fluctuation, but is sensitive to economic conditions.

 

The Interstate Commerce Act exempts from regulation water transportation of certain dry-bulk commodities. In 2003, all transportation services provided by TECO Transport’s subsidiaries were within this exemption.

 

TECO Transport’s subsidiaries are subject to the provisions of the Clean Water Act of 1977 which authorizes the Coast Guard and the EPA to assess penalties for oil and hazardous substance discharges. Under this Act, these agencies are also empowered to assess clean-up costs for such discharges. In 2003, TECO Transport spent $0.3 million for environmental compliance. Environmental expenditures are estimated at $0.2 million in 2004, 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.

 

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TECO COAL

 

TECO Coal owns no operating assets but holds all of the common stock of Gatliff Coal Company, Rich Mountain Coal Company, Clintwood Elkhorn Mining Company, Pike-Letcher Land Company, Premier Elkhorn Coal Company, Bear Branch Coal Company, Perry County Coal Corporation, and TECO Synfuel Operations, LLC. The TECO Coal subsidiaries own or control mineral rights, and own or operate surface and underground mines, synthetic fuel production facilities and coal processing and loading facilities in eastern Kentucky, Virginia and Tennessee. TECO Coal and its subsidiaries had 713 employees as of Dec. 31, 2003.

 

In 2003, TECO Coal subsidiaries sold 9.2 million tons of coal, with 100 percent sold to parties other than Tampa Electric. Of the total sold, 5.8 million tons were produced and sold as synthetic fuel.

 

In 2000, TECO Coal acquired Perry County Coal Corporation (Perry County), which owns or controls in excess of 21 million tons of low sulfur reserves and operates both deep and surface contract mines along with a preparation plant and two loadouts. Perry County produced and sold 2.6 million tons of coal in 2003.

 

In April 2003, TECO Coal sold a 49.5-percent interest in its synthetic fuel production facilities located at its operations in eastern Kentucky. (See the TECO Coal section of MD&A) The 5.8 million tons of synfuel produced in 2003 replaced some of TECO Coal’s conventional coal production in 2003. Sales of the fuel processed through these types of facilities are eligible for non-conventional fuels tax credits under Section 29 of the Internal Revenue Code, which are available through 2007. TECO Coal received 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 interest in the production facilities.

 

The Section 29 tax credit is determined annually and is estimated to be $1.11 per million Btu in 2003, $1.09 per million Btu in 2002 and $1.08 per million Btu in 2001. This rate escalates with inflation but could be limited by domestic oil prices. In 2003, domestic oil prices would have had to exceed $50 per barrel for the limitation to have been effective. In 2003, TECO Coal’s Section 29 tax credits were $66.0 million, compared to $107.3 million in 2002 and $86.2 million in 2001.

 

Primary competitors of TECO Coal’s subsidiaries are other coal suppliers, many of which are located in Central Appalachia. To date, TECO Coal has been able to compete for coal sales by mining high-quality steam and specialty coals and by effectively managing production and processing costs.

 

The operations of underground mines, including all related surface facilities, are subject to the Federal Coal Mine Safety and Health Act of 1977. TECO Coal’s subsidiaries are also subject to various Kentucky, Tennessee and Virginia mining laws which require approval of roof control, ventilation, dust control and other facets of the coal mining business. Federal and state inspectors inspect the mines to ensure compliance with these laws. TECO Coal believes it is in substantial compliance with the standards of the various enforcement agencies. It is unaware of any mining laws or regulations that would materially affect the market price of coal sold by its subsidiaries.

 

TECO Coal’s subsidiaries are subject to various federal, state and local air and water pollution standards in their mining operations. In 2003, TECO Coal spent approximately $1.5 million on environmental protection and reclamation programs. TECO Coal expects to spend a similar amount in 2004 on these programs.

 

Coal mining operations are also subject to the Surface Mining Control and Reclamation Act of 1977 which places a charge of $0.15 and $0.35 on every net ton of underground and surface coal mined, respectively, to create a fund for reclaiming land and water adversely affected by past coal mining. Other provisions establish standards for the control of environmental effects and reclamation of surface coal mining and the surface effects of underground coal mining and requirements for federal and state inspections.

 

TECO SOLUTIONS

 

TECO Solutions was formed during the early stages of Florida’s proposed electric industry restructuring, as a vehicle through which to support TECO Energy’s strategy of offering customers (primarily in Florida) a comprehensive and competitive package of energy services and products, including energy-efficient engineering and construction and gas management services. The subsequent rollback of the proposed deregulation and TECO Energy’s refocus 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 that previously were part of TECO Solutions. Operating companies under TECO Solutions include TECO BCH Mechanical, TECO Gas Services Inc., TECO Propane Ventures LLC (TPV) and TECO Partners, Inc., with total employees of 655 as of Dec. 31, 2003.

 

TECO BCH Mechanical and its affiliated companies (BCH), one of Florida’s leading mechanical contracting firms, is headquartered in Largo, Florida and has offices in Cocoa Beach and Ft. Lauderdale. It provides air-conditioning, electrical and plumbing systems, and repair and maintenance services to more than 750 institutional and commercial customers throughout Florida.

 

TECO Gas Services provides gas management services to cogeneration facilities in Florida. On July 21, 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.

 

TECO BGA, Inc. (formerly a component of TECO Energy Services) (BGA) is an engineering energy services company headquartered in Tampa, providing engineering, construction management and energy services to more than 300 customers. Effective Jan. 1, 2004, the company completed the sale of BGA to an entity owned by an employee group. BGA’s results are accounted for as continuing operations for all periods reported.

 

Prior Energy, a leading natural gas management company headquartered in Mobile, Alabama, serves customers throughout the Southeast. Prior Energy owns no operating assets. In December 2003, TECO Solutions entered into an agreement to sell this end use gas marketing company; effective Feb. 1, 2004, the sale of Prior Energy was completed. Prior Energy’s results are accounted for as discontinued operations for all periods reported.

 

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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 January 2004, U.S. Propane completed the sale of its direct and indirect equity investments in Heritage Propane Partner, L.P. (Heritage). The sale, part of a larger transaction that involved the merging of privately held Energy Transfer Company with Heritage, was announced in November 2003. TPV owns no operating assets.

 

TECO COALBED METHANE

 

TECO Coalbed Methane, Inc. had developed jointly with another entity the natural gas production from coal seams in Alabama’s Black Warrior Basin. In September 2002, TECO Energy initiated activities to sell the TECO Coalbed Methane gas assets. That sale was substantially completed in December 2002 to the Municipal Gas Authority of Georgia. Proceeds for the sale were $140 million, of which $42 million was paid in cash at closing and $98 million was paid in January 2003. TECO Coalbed Methane’s results are accounted for as discontinued operations for all periods reported. Following the sale of substantially all of its assets, TECO Coalbed Methane, Inc. was merged with and into TECO Coalbed Methane Florida, Inc.

 

Production from TECO Coalbed Methane’s reserves was eligible for Section 29 non-conventional fuels tax credits through 2002. The credit was $1.09 per million Btu for 2002 and $1.08 per million Btu in 2001. This rate escalated with inflation but could be limited by domestic oil prices. In 2002, domestic oil prices would have had to exceed $49 per barrel for this limitation to have been effective. In 2002, TECO Coalbed Methane’s Section 29 tax credits were $15.9 million, compared to $16.1 million in 2001. TECO Coalbed Methane’s operations are subject to federal, state and local regulations for air emissions and water and waste disposal.

 

Item 2. PROPERTIES.

 

TECO Energy believes that the physical properties of its operating companies are adequate to carry on their businesses as currently conducted. The properties of Tampa Electric and most of the subsidiaries of TECO Wholesale Generation are generally subject to liens securing long-term debt.

 

TAMPA ELECTRIC

 

At Dec. 31, 2003, Tampa Electric had five electric generating plants and four combustion turbine units in service with a total net winter generating capability of 3,256 megawatts, including Big Bend (1,759-MW capability from four coal units), Bayside (752-MW capability from one natural gas unit), Phillips (34-MW capability from two diesel units), Polk (260-MW capability from one integrated gasification combined cycle (IGCC) unit), two combustion turbine units (CTs) located at Big Bend (85-MW each) 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 September 1996. In 1991, Tampa Electric purchased two power plants (Dinner Lake and Phillips) from the Sebring Utilities Commission (Sebring). Dinner Lake (11-MW capability from one natural gas unit) and Phillips were placed in service by Sebring in 1966 and 1983, respectively. In March 1994, Dinner Lake Station was placed on long-term reserve standby and was retired from service in January 2003. Hookers Point Station’s Unit 5 (67-MW) was placed on long-term standby in January 2001. All units at Hookers Point were retired from service in January 2003.

 

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 1,774 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 and the U.S. Environmental Protection Agency (EPA), and the Florida Department of Environmental Protection (DEP) required all coal burning to cease by the end of 2004, but allows the units to be repowered on natural gas.

 

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Tampa Electric owns 187 substations having an aggregate transformer capacity of 19,825 MVA. The transmission system consists of approximately 1,308 pole miles of high voltage transmission lines, and the distribution system consists of 7,038 pole miles of overhead lines and 3,252 trench miles of underground lines. As of Dec. 31, 2003, there were 612,465 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 15,000 miles of pipe, including approximately 9,500 miles of mains and over 5,500 miles of service lines. Mains and service lines are maintained under rights-of-way, franchises or permits.

 

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

 

TECO WHOLESALE GENERATION (FORMERLY TECO POWER SERVICES)

 

TWG Merchant Operating Segment

 

TWG indirectly holds a 100-percent ownership interest in TECO-Panda Generating Company, LP, which owns 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. The first 550-megawatt power block of Union began operating in January 2003 with all power blocks in operation by June 2003. 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 TECO Wholesale Generation, Inc. section of MD&A for a discussion of the expected transfer of the ownership of these projects.

 

Frontera Generation, LP owns 40 acres of land in Hidalgo County, Texas on which the 477-megawatt gas-fired combined cycle Frontera electric generation plant is located.

 

TM Delmarva Power, LLC has a 100-percent economic interest in Commonwealth Chesapeake Company, LLC, which owns approximately 105 acres of land outside of New Church, in Accomack County, Virginia on which the 315-megawatt oil-fired single cycle Commonwealth Chesapeake Power Station is located.

 

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

 

Other Unregulated Companies Operating Segment

 

The company, through its indirect subsidiary TPS Hamakua Land, Inc., has a 50-percent indirect interest in Hamakua Land Partnership, LLP, which owns 140 acres in Hawaii on which the Hamakua Energy Project is located.

 

TPS Guatemala One, Inc. has a 96.06-percent interest in TCAE, which owns 7 acres in Guatemala on which the Alborada Power Station is located. TPS San Jose, LDC has a 100-percent ownership in a project entity, CGESJ, which owns 190 acres in Guatemala on which the San Jose Power Station is located.

 

In 2003, Hardee Power Partners, Ltd. (HPP), which owned a 370-MW gas-fired generation facility located in central Florida, was sold to an affiliate of Invenergy LLC and GTCR Golden Rauner LLC. Under the terms of the sale, subsidiaries of the company will continue to provide service to HPP under the existing operation and maintenance agreement. The new owner may, at any time, choose to cancel this agreement.

 

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TECO TRANSPORT

 

TECO Bulk Terminal’s storage and transfer terminal is on a 1,070-acre site fronting on the Mississippi River, approximately 40 miles south of New Orleans. Bulk Terminal owns 342 of these acres in fee, with the remainder held under long-term leases.

 

TECO Barge operates a fleet of 18 towboats and 726 river barges, approximately 87 percent of which it owns, on the Mississippi, Ohio and Illinois rivers. 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, 2003, TECO Ocean Shipping owned and operated 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

 

TECO Coal, through its subsidiaries, controls approximately 179,000 acres of coal reserves and mining property in Kentucky, Virginia and Tennessee.

 

Property

 

Gatliff Coal Company controls approximately 11,000 acres of coal and mining properties and has operations in Campbell County, Tennessee, as well as in Bell, Knox and Whitley Counties, Kentucky. Additionally, in east central Kentucky, Bear Branch Coal Company and Perry County Coal Corporation control 50,000 acres of coal reserves and operate in Perry, Leslie and Knott Counties. In eastern Kentucky, Premier Elkhorn Coal Company and Pike-Letcher Land Company are located in Letcher and Pike Counties where they control 50,000 acres of properties. Clintwood Elkhorn Mining also operates in Pike County, Kentucky, as well as in Buchanan County Virginia. Clintwood Elkhorn controls 68,000 acres of property.

 

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

 

Facilities

 

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

 

Company


 

Facility


 

Location


 

Railroad Service


 

Utility Service


Gatliff Coal   Ada Tipple   Himyar, KY   CSX Railroad   RECC
Clintwood Elkhorn   Clintwood #2 Plant   Biggs, KY   Norfolk Southern   American Electric Power
Clintwood Elkhorn   Clintwood #3 Plant   Hurley, VA   Norfolk Southern   American Electric Power
Premier Elkhorn   Burk Branch Plant   Myra, KY   CSX Railroad   American Electric Power
Perry County Coal   Perry County Plant   Hazard, KY   CSX Railroad   American Electric Power

 

Significant projects completed in 2003 included completion of preparation plant upgrades at Perry County.

 

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Table of Contents

Coal Reserves

 

As of Dec. 31, 2003, the TECO Coal Corporation operating companies have a combined estimated 219.4 million tons of recoverable reserves, all of which are assigned. The reserves are proven and probable. All of the reserves consist of High Vol A Bituminous coal. Reserves are generally considered to be tonnages that are proven and probable and meet the generally accepted mining criteria including, but not limited to, mining height, preparation plant recovery, and strip ratio. These reserves are generally projected to be mined and sold at a profit, based on year-end price and cost levels. When calculating reserves, TECO Coal has assumed the following recovery rates for the various mining methods:

 

     Mining Recovery Rates

 

Underground

   52 %

Contour, Surface

   85 %

Point Removal/Mt. Top

   90 %

Auger

   30 %

Highwall Miner

   50 %

 

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

 

     Average Quality

   Assigned Reserves

   Surface
Reserves
(000s)


   Underground
Reserves
(000s)


   Total
Reserves
(000s)


Company


   BTU/lb.

   %
Ash


   %
Sulfur


   %
Owned


   %
Leased


        

Gatliff Coal

   14,586    3.84    0.96    0    100    1,800    9,492    11,292

Perry County Coal

   13,091    7.20    0.90    0    100    5,609    15,795    21,404

Bear Branch

   13,227    6.23    0.92    0    100    —      69,899    69,899

Premier Elkhorn Coal/Pike Letcher Land (1)

   13,976    6.78    1.16    90    10    19,655    53,700    73,355

Clintwood Elkhorn Mining

   14,198    7.35    1.05    10    90    12,141    31,345    43,486
    
  
  
  
  
  
  
  

Total Reserves

   13,726    6.61    1.03              39,205    180,231    219,436
    
  
  
  
  
  
  
  

 

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

 

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

 

Region/Company


  

Product


   BTU/lb.

  

%

Ash


   %
Sulfur


   Reserves
(000s)


   % by
Region


East Central Kentucky

                             

Gatliff Coal

   Steam coal    14,586    3.84    0.96    11,292    5.15

Perry County Coal

   Steam coal    14,076    7.74    0.97    21,404    9.75

Bear Branch Coal

   Steam coal    14,223    6.70    0.99    69,899    31.85
    
  
  
  
  
  
                         102,595    46.75
    
  
  
  
  
  

Eastern Kentucky

                             

Premier/Pike Letcher Land

   Steam coal    13,976    6.78    1.16    73,355    33.43

Clintwood

   Steam coal    12,713    13.40    1.08    1,309    0.60

Clintwood

   Metallurgical coal    14,429    6.51    1.08    20,521    9.35
    
  
  
  
  
  
                         95,185    43.38
    
  
  
  
  
  

Southwestern Virginia

                             

Clintwood

   Steam coal    12,713    13.40    1.08    6,650    3.03

Clintwood

   Metallurgical coal    14,621    5.37    1.01    15,006    6.84
    
  
  
  
  
  
                         21,656    9.87
    
  
  
  
  
  

Total

                       219,436    100.00
    
  
  
  
  
  

 

TECO Coal Corporation’s reserves are based on over 1700 data points, including drill holes, prospect measurements, and mine measurements. Reserve classification is determined by evaluation of engineering and geologic information along with economic analysis. These reserves are adjusted periodically to reflect fluctuations in the economics in the market and/or changes in engineering parameters and/or geologic conditions. The information is assembled by qualified geologists and engineers located throughout the company. The information is constantly being updated to reflect new data for existing property as well as new acquisitions and depleted reserves. Information is entered into sophisticated computer modeling programs from which preliminary reserves estimations are generated. Final determinations of reserves are made after in-house geologists have reviewed the computer models and manipulated the grids to better reflect regional trends.

 

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Table of Contents

TECO COALBED METHANE

 

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

 

Item 3. LEGAL PROCEEDINGS.

 

TM Delmarva Power Arbitration Proceeding

 

A dispute resulting in an arbitration proceeding was brought against a TWG subsidiary, TM Delmarva Power, L.L.C. (TMDP), by the non-equity member, NCP of Virginia, L.L.C. (NCP), in the Commonwealth Chesapeake Project (CCC). The arbitration panel, in a 2-to-1 decision, found in favor of NCP and issued an interim award on Dec. 17, 2002 and, after several briefing cycles and a reopened hearing, issued its final award in September 2003.

 

Under the award TMDP is obligated to acquire NCP’s voting and other rights, pay NCP interest on the deemed acquisition price from a pre-determined date, and pay NCP’s legal fees as prescribed under the final award. The forced acquisition created a pre-tax loss of $32.0 million, representing the excess of the purchase price over the fair value of the interests acquired. TMDP is seeking to vacate the arbitration award in the U.S. District Court for the District of Columbia and has not yet paid the amount of the award. As of Dec. 31, 2003, the company has reserved for the full $46.9 million, representing the maximum payment obligation for the award plus accrued interest. The vacatur proceeding is still pending, and is expected to be completed in the third or fourth quarter of 2004.

 

Other Actions

 

In March 2001, TWG (under its former name of TECO Power Services) was served with a lawsuit filed in the Circuit Court for Hillsborough County by a Tampa-based firm called Grupo Interamerica, L.L.C. (“Grupo”) in connection with a potential investment in a power project in Columbia in 1996. Grupo alleges, among other things, that TWG breached an oral contract with Grupo that would have allowed Grupo to acquire up to a 20-percent interest in the Columbian wholesale generation project when TWG declined to invest in such project. Grupo is seeking damages equal to the net present value of 20-percent of the project over its life. TWG disputes the allegations and denies liability since any understanding made regarding the investment in the project was subject to TECO Energy Board approval which was not obtained. A trial date has not been set.

 

Three lawsuits have been filed in the Circuit Court in Hillsborough County against Tampa Electric, in connection with the location of transmission structures in certain residential areas, by residents in the areas surrounding the structures. The high-voltage power lines are needed by Tampa Electric to move electricity to the northwest part of its service territory where population growth has been experienced. The residents are seeking to remove the poles or to receive monetary damages. Tampa Electric is working with the community to determine the feasibility of alternate routes or structures or some combination.

 

See also the Enron Related Matters and Superfund and Former Manufactured Gas Plant Sites sections of MD&A and the discussion of environmental matters in Note 20 to the TECO Energy Consolidated Financial Statements and Note 14 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 2003 to a vote of TECO Energy’s security holders, through the solicitation of proxies or otherwise.

 

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EXECUTIVE OFFICERS OF THE REGISTRANT

 

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

 

Name


   Age

  

Current Positions and Principal

Occupations During Last Five Years


Robert D. Fagan

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

Charles R. Black

   53    Senior Vice President-Generation, September 2003 to date; Vice President-Energy Supply, Energy and Construction, Tampa Electric Company, February 2000 to September 2003; Vice President-Energy Supply, Tampa Electric Company, November 1996 to February 2000.

William N. Cantrell

   51    President, Tampa Electric Company, September 2003 to date, President, Peoples Gas System, April 2000 to date and President, TECO Solutions, Inc., September 2000 to date; President, Peoples Gas Companies, June 1997 to April 2000, and President, Bosek, Gibson and Associates, Inc., January 1998 to September 2000.

Clinton E. Childress

   55    Senior Vice President-Human Resources and Services, September 2003 to date; Chief Human Resources Officer, July 2000 to September 2003; and prior thereto, Director of Compensation and Benefits.

Gordon L. Gillette

   44    Senior Vice President-Finance and Chief Financial Officer, April 2001 to date; Vice President-Finance and Chief Financial Officer, April 1998 to April 2001.

Richard Lehfeldt

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

Sheila M. McDevitt

   57    Senior Vice President-General Counsel, April 2001 to date; Vice President-General Counsel, January 1999 to April 2001; and prior thereto, Vice President-Assistant General Counsel.

John B. Ramil

   48    Executive Vice President and Chief Operating Officer, September 2003 to date; Executive Vice President, December 2002 to September 2003; President, Tampa Electric Company, April 1998 to September 2003.

D. Jeffrey Rankin

   57    President of TECO Transport Corporation, since prior to 1999.

J. J. Shackleford

   57    President of TECO Coal Corporation, since prior to 1999.

 

There is no family relationship between any of the persons named above. The term of office of each officer extends to the meeting of the Board of Directors following the next annual meeting of shareholders, scheduled to be held on April 28, 2004, and until such officer’s successor is elected and qualified.

 

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Table of Contents

PART II

 

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

 

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

 

     1st Quarter

   2nd Quarter

   3rd Quarter

   4th Quarter

2003

                           

High

   $ 17.00    $ 13.69    $ 14.20    $ 14.85

Low

   $ 9.47    $ 10.05    $ 11.50    $ 11.80

Close

   $ 10.63    $ 11.99    $ 13.82    $ 14.41

Dividend

   $ 0.355    $ 0.19    $ 0.19    $ 0.19

2002

                           

High

   $ 28.94    $ 29.05    $ 24.71    $ 16.48

Low

   $ 23.40    $ 22.70    $ 14.20    $ 10.02

Close

   $ 28.63    $ 24.75    $ 15.88    $ 15.47

Dividend

   $ 0.345    $ 0.355    $ 0.355    $ 0.355

 

The approximate number of shareholders of record of common stock of TECO Energy as of Feb. 29, 2004 was 22,097.

 

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 stockholders is dividends and other distributions from its operating companies. Tampa Electric’s first mortgage bond indenture and certain long-term debt at PGS contain restrictions that limit the payment of dividends and distributions on the common stock of Tampa Electric Company. Tampa Electric’s first mortgage bond indenture does not limit loans or advances. As of Dec. 31, 2003 and 2002, balances restricted as to transfers from Tampa Electric to TECO Energy under the first mortgage bonds were 3% and 20%, respectively, of consolidated common equity. Tampa Electric’s new credit facilities include a covenant limiting cumulative distributions and outstanding affiliate loans. (See the Restrictions on Dividend Payments and Transfer of Assets section in Note 1 to the TECO Energy Consolidated Financial Statements.)

 

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 Merrill Lynch credit facility contains a covenant that could limit the payment of dividends exceeding $40 million in any quarter under certain circumstances if the facility is drawn. (See Covenants in Financing Agreements section of MD&A, and Notes 6, 7 and 20 to the TECO Energy Consolidated Financial Statements for a more detailed description of significant financial covenants.

 

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.

 

TECO Energy has 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 $151.4 million in 2003, $197.4 million in 2002 and $171.8 million for 2001. 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.

 

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Table of Contents
Item 6. SELECTED FINANCIAL DATA.

 

A summary of selected financial information for TECO Energy, Inc. for each of the last five fiscal years, is set forth under the heading Selected Financial Data in the 2003 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.

 

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

 

A discussion of TECO Energy, Inc.’s consolidated results of operations and financial condition is set forth on under the heading Management’s Discussion & Analysis of Financial Condition & Results of Operations in the 2003 Annual Report, which discussion is hereby incorporated by reference and filed as part of Exhibit 13 to this report.

 

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

 

Information responding to Item 7A appears in the 2003 Annual Report under the heading Management’s Discussion & Analysis of Financial Condition & Results of Operations — Disclosures About Market Risk, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.

 

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Table of Contents
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

 

TECO ENERGY, INC.

 

Information responding to Item 8 for TECO Energy, Inc., appears in the 2003 Annual Report under the following headings: Consolidated Financial Statements — Consolidated Balance Sheets, Consolidated Financial Statements — Consolidated Statements Of Income, Consolidated Financial Statements — Consolidated Statements of Comprehensive Income, Consolidated Financial Statements — Consolidated Statements of Cash Flows, Consolidated Financial Statements — Consolidated Statements of Common Equity, Notes to the Consolidated Financial Statements, and Report of Independent Certified Public Accountants, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.

 

     Page No.

Report of Independent Certified Public Accountants on Financial Statement Schedules

   24

Financial Statement Schedule I – Condensed Parent Company Financial Statements

   54-57

Financial Statement Schedule II – Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2003, 2002 and 2001

   58

Signatures

   60

 

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

 

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Report of Independent Certified Public Accountants on Financial Statement Schedules

 

To the Board of Directors of TECO Energy, Inc.:

 

Our audits of the consolidated financial statements referred to in our report dated March 2, 2004 appearing in the 2003 Annual Report to Shareholders of TECO Energy, Inc. (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

 

/s/ PricewaterhouseCoopers LLP

 

Tampa, Florida

March 2, 2004

 

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TAMPA ELECTRIC COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

     Page No.

Report of Independent Certified Public Accountants

   26

Consolidated Balance Sheets, Dec. 31, 2003 and 2002

   27-28

Consolidated Statements of Income for the years ended Dec. 31, 2003, 2002 and 2001

   29

Consolidated Statements of Comprehensive Income for the years ended Dec. 31, 2003, 2002 and 2001

   29

Consolidated Statements of Cash Flows for the years ended Dec. 31, 2003, 2002 and 2001

   30

Consolidated Statements of Retained Earnings for the years ended Dec. 31, 2003, 2002 and 2001

   31

Consolidated Statements of Capitalization, Dec. 31, 2003 and 2002

   31-33

Notes to Consolidated Financial Statements

   34-50

Financial Statement Schedule II – Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2003, 2002 and 2001

   59

Signatures

   61

 

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

 

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Table of Contents

REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

 

To the Board of Directors and Shareholders of Tampa Electric Company:

 

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Tampa Electric Company and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a) (2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

/s/ PricewaterhouseCoopers LLP

 

Tampa, Florida

March 2, 2003

 

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TAMPA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

 

Assets

(millions) Dec. 31,


   2003

    2002

 

Property, plant and equipment

                

Utility plant in service

                

Electric

   $ 4,693.5     $ 4,310.8  

Gas

     778.2       746.7  

Construction work in progress

     470.0       768.5  
    


 


Property, plant and equipment, at original costs

     5,941.7       5,826.0  

Accumulated depreciation

     (1,808.2 )     (1,720.4 )
    


 


       4,133.5       4,105.6  

Other property

     3.7       7.9  
    


 


Total property, plant and equipment

     4,137.2       4,113.5  
    


 


Current assets

                

Cash and cash equivalents

     33.6       6.9  

Receivables, less allowance for uncollectibles of $1.1 million and $1.1 million at Dec. 31, 2003 and 2002, respectively

     186.0       186.5  

Inventories

                

Fuel, at average cost

     71.2       79.1  

Materials and supplies

     43.8       48.1  

Prepayments and other

     22.8       18.4  
    


 


Total current assets

     357.4       339.0  
    


 


Deferred debits

                

Deferred income taxes

     133.5       133.3  

Unamortized debt expense

     23.2       23.7  

Regulatory assets

     188.3       163.2  

Other

     0.1       5.6  
    


 


Total deferred debits

     345.1       325.8  
    


 


Total assets

   $ 4,839.7     $ 4,778.3  
    


 


 

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

 

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TAMPA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (continued)

 

Liabilities and capital

(millions) Dec. 31,


   2003

   2002

Capital

             

Common stock

   $ 1,376.8    $ 1,535.1

Retained earnings

     274.9      302.9
    

  

Total capital

     1,651.7      1,838.0

Long-term debt, less amount due within one year

     1,590.9      1,345.6
    

  

Total capitalization

     3,242.6      3,183.6
    

  

Current liabilities

             

Long-term debt due within one year

     6.1      81.0

Notes payable

     —        10.5

Accounts payable

     167.9      178.8

Customer deposits

     101.4      94.6

Interest accrued

     26.7      18.3

Taxes accrued

     82.9      46.9
    

  

Total current liabilities

     385.0      430.1
    

  

Deferred credits

             

Deferred income taxes

     474.5      483.1

Investment tax credits

     22.6      27.1

Regulatory liabilities

     560.2      538.7

Other

     154.8      115.7
    

  

Total deferred credits

     1,212.1      1,164.6
    

  

Total liabilities and capital

   $ 4,839.7    $ 4,778.3
    

  

 

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

 

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TAMPA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

 

(millions)

For the years ended Dec. 31,


   2003

    2002

    2001

 

Revenues

                        

Electric (includes franchise fees and gross receipts taxes of $64.4 million in 2003, $63.5 million in 2002, and $56.0 million in 2001)

   $ 1,585.4     $ 1,582.5     $ 1,411.8  

Gas (includes franchise fees and gross receipts taxes of $13.3 million in 2003, $10.3 million in 2002, and $15.1 million in 2001)

     408.4       318.1       352.9  
    


 


 


Total revenues

   $ 1,993.8       1,900.6       1,764.7  
    


 


 


Expenses

                        

Operations

                        

Fuel

     443.3       424.1       346.5  

Purchased power

     234.9       253.7       209.7  

Cost of natural gas sold

     224.0       148.9       186.4  

Other

     257.7       256.4       249.1  

Maintenance

     94.3       112.0       103.2  

Depreciation

     243.0       220.1       201.3  

Restructuring charges

     14.0       16.6       —    

Taxes, federal and state income

     94.0       100.3       97.7  

Taxes, other than income

     136.7       132.6       129.3  
    


 


 


Total expenses

     1,741.9       1,664.7       1,523.2  
    


 


 


Income from operations

     251.9       235.9       241.5  
    


 


 


Other (expense) income

                        

Allowance for other funds used during construction

     19.8       24.9       6.6  

Other income, net

     1.2       1.5       4.1  

Asset impairment (net of income tax benefit of $30.7 million)

     (48.9 )     —         —    

Total other (expense) income

     (27.9 )     26.4       10.7  

Interest charges

                        

Interest on long-term debt

     102.7       77.5       62.5  

Other interest

     5.5       (1.6 )     15.2  

Allowance for borrowed funds used during construction

     (7.6 )     (9.6 )     (2.6 )
    


 


 


Total interest charges

     100.6       66.3       75.1  
    


 


 


Net income

   $ 123.4     $ 196.0     $ 177.1  
    


 


 


CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

 

(millions)

For the years ended Dec. 31,


   2003

    2002

    2001

 

Net income

   $ 123.4     $ 196.0     $ 177.1  
    


 


 


Other comprehensive (loss) income, net of tax

                        

Net unrealized gain (loss) on cash flow hedges

     —         0.1       (0.1 )
    


 


 


Other comprehensive income (loss), net of tax

     —         0.1       (0.1 )
    


 


 


Comprehensive income

   $ 123.4     $ 196.1     $ 177.0  
    


 


 


 

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

 

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TAMPA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

(millions)

For the years ended Dec. 31,


   2003

    2002

    2001

 

Cash flows from operating activities

                        

Net income

   $ 123.4     $ 196.0     $ 177.1  

Adjustments to reconcile net income to net cash from operating activities:

                        

Depreciation

     243.0       220.1       201.3  

Deferred income taxes

     (23.9 )     23.6       (2.0 )

Investment tax credits, net

     (4.6 )     (4.4 )     (4.5 )

Allowance for funds used during construction

     (27.4 )     (34.5 )     (9.2 )

Loss on sales of assets, pre-tax

     0.8       —         —    

Asset impairment, pre-tax

     79.6       —         —    

Deferred recovery clause

     (27.3 )     72.2       (19.0 )

Refunded to customers

     —         (6.4 )     —    

Receivables, less allowance for uncollectibles

     0.5       (19.8 )     19.1  

Inventories

     12.2       (7.2 )     (10.8 )

Prepayments and other deposits

     (3.1 )     (2.4 )     (9.2 )

Taxes accrued

     36.0       (10.4 )     (14.3 )

Interest accrued

     8.4       2.3       (18.1 )

Accounts payable

     (10.8 )     43.1       (52.4 )

Other

     70.4       2.5       35.2  
    


 


 


Cash flows from operating activities

     477.2       474.7       293.2  
    


 


 


Cash flows from investing activities

                        

Capital expenditures

     (331.7 )     (685.7 )     (499.3 )

Allowance for funds used during construction

     27.4       34.5       9.2  

Net proceeds from sales of assets

     4.3       —         —    
    


 


 


Cash flows from investing activities

     (300.0 )     (651.2 )     (490.1 )
    


 


 


Cash flows from financing activities

                        

Proceeds from contributed capital from parent

     —         217.0       170.0  

Return of contributed capital to parent

     (158.3 )     —         —    

Proceeds from long-term debt

     250.0       689.3       250.0  

Repayment of long-term debt

     (80.3 )     (302.4 )     (54.4 )

Net (decrease) increase in short-term debt

     (10.5 )     (238.5 )     17.8  

Payment of dividends

     (151.4 )     (197.4 )     (171.8 )
    


 


 


Cash flows from financing activities

     (150.5 )     168.0       211.6  
    


 


 


Net (decrease) increase in cash and cash equivalents

     26.7       (8.5 )     14.7  

Cash and cash equivalents at beginning of year

     6.9       15.4       0.7  
    


 


 


Cash and cash equivalents at end of year

   $ 33.6     $ 6.9     $ 15.4  
    


 


 


Supplemental disclosure of cash flow information

                        

Cash paid during the year for:

                        

Interest

   $ 109.4     $ 74.0     $ 85.3  

Income taxes

   $ 61.9     $ 143.9     $ 119.9  
    


 


 


 

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

 

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TAMPA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

 

(millions)

For the years ended Dec. 31,


   2003

   2002

   2001

Balance, beginning of year

   $ 302.9    $ 304.3    $ 299.0

Add: Net income

     123.4      196.0      177.1
    

  

  

       426.3      500.3      476.1
    

  

  

Deduct: Cash dividends on capital stock Common

     151.4      197.4      171.8
    

  

  

       151.4      197.4      171.8
    

  

  

Balance, end of year

   $ 274.9    $ 302.9    $ 304.3
    

  

  

 

CONSOLIDATED STATEMENTS OF CAPITALIZATION

 

(millions, except share amounts)


   Current
Redemption
Price


  

Capital Stock
Outstanding

Dec. 31,


  

Cash dividends

paid (1)


      Shares

   Amount

   Per
Share


   Amount

Common stock — without par value

                            

25 million shares authorized

                            

2003

   N/A    10    $ 1,376.8    N/A    $ 151.4

2002

   N/A    10    $ 1,535.1    N/A    $ 197.4

Preferred stock — $100 par value

                            

1.5 million shares authorized, none outstanding

                            

Preferred stock – no par

                            

2.5 million shares authorized, none outstanding

                            

Preference stock – no par

                            

2.5 million shares authorized, none outstanding

                            

 

(1) Quarterly dividends paid on Feb. 15, May 15, Aug. 15 and Nov. 15.

 

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

 

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TAMPA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)

 

Long-Term Debt

(millions) Dec. 31,


   Due

   2003

    2002

 

Tampa Electric

                     

First mortgage bonds (issuable in series):

                     

7.75% (effective rate of 7.96%)

   2022    $ 75.0     $ 75.0  

6.125% (effective rate of 6.61%)

   2003      —         75.0  

Installment contracts payable (1):

                     

6.25% Refunding bonds (effective rate of 6.81%) (2)

   2034      86.0       86.0  

5.85% Refunding bonds (effective rate of 5.88%)

   2030      75.0       75.0  

5.1% Refunding bonds (effective rate of 5.77%) (3)

   2013      60.7       60.7  

5.5% Refunding bonds (effective rate of 6.34%) (3)

   2023      86.4       86.4  

4% (effective rate of 4.22%) (4)

   2025      51.6       51.6  

4% (effective rate of 4.17%) (4)

   2018      54.2       54.2  

4.25% (effective rate of 4.44%) (4)

   2020      20.0       20.0  

Notes: 6.875% (effective rate of 6.98%) (5)

   2012      210.0       210.0  

  6.375% (effective rate of 7.35%) (5)

   2012      330.0       330.0  

  5.375% (effective rate of 5.59%) (5)

   2007      125.0       125.0  

  6.25% (effective rate of 6.31%) (5)

   2016      250.0       —    
    
  


 


            1,423.9       1,248.9  
         


 


Peoples Gas System

                     

Senior Notes: (6) 10.35%

   2007      3.4       4.2  

10.33%

   2008      4.8       5.6  

10.3%

   2009      6.4       7.2  

9.93%

   2010      6.6       7.4  

8.0%

   2012      23.3       25.4  

Notes: 6.875% (effective rate of 6.98%) (5)

   2012      40.0       40.0  

   6.375% (effective rate of 7.34%) (5)

   2012      70.0       70.0  

   5.375% (effective rate of 5.58%) (5)

   2007      25.0       25.0  
    
  


 


            179.5       184.8  
         


 


            1,603.4       1,433.7  

Unamortized debt premium (discount), net

          (6.4 )     (7.1 )
         


 


            1,597.0       1,426.6  

Less amount due within one year (7)

          6.1       81.0  
         


 


Total long-term debt

        $ 1,590.9     $ 1,345.6  
         


 


(1) Tax exempt securities.

 

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

 

(3) Proceeds on these bonds were used to refund bonds with interest rates of 5.75% to 8%.

 

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

 

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

 

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

 

(7) Of the amount due in 2004, $0.8 million may be satisfied by the substitution of property in lieu of cash payments.

 

A substantial part of the tangible assets of Tampa Electric is pledged as collateral to secure its first mortgage bonds, and certain pollution control equipment is pledged to secure installment contracts payable. Maturities and annual sinking fund requirements of long-term debt for the years 2005, 2006, 2007 and 2008 are $5.5 million, $5.9 million, $156.1 million and $5.7 million, respectively.

 

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TAMPA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)

 

At Dec. 31, 2003, total long-term debt had a carrying amount of $1,590.9 million and an estimated fair market value of $1,697.4 million. The estimated fair market value of long-term debt was based on quoted market prices for the same or similar issues, on the current rates offered for debt of the same remaining maturities, or for long-term debt issues with variable rates that approximate market rates, at carrying amounts. The carrying amount of long-term debt due within one year approximated fair market value because of the short maturity of these instruments.

 

In April 2003, Tampa Electric issued $250 million of 6.25% Senior Notes due in 2016, in a private placement. Net proceeds of approximately $250 million were used to repay short-term indebtedness and for general corporate purposes. The 6.25% Senior Notes contain covenants that (1) require Tampa Electric Company to maintain, as of the last day of each fiscal quarter, a debt-to-capital ratio, as defined in the agreement, that does not exceed 60%, and (2) prohibit the creation of any liens on any of its property in excess of $787 million in the aggregate, with certain exceptions, as defined, without equally and ratably securing the 6.25% Senior Notes.

 

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

 

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TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1. Significant Accounting Policies

 

The significant accounting policies are as follows:

 

Principles of Consolidation

 

Tampa Electric Company is a wholly-owned subsidiary of TECO Energy, Inc, and is comprised of the Electric division, generally referred to as Tampa Electric, and the Natural Gas division, generally referred to as Peoples Gas System (PGS).

 

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

 

The use of estimates is inherent in the preparation of financial statements in accordance with generally accepted accounting principles (GAAP). Actual results could differ from these estimates.

 

Planned Major Maintenance

 

Tampa Electric and PGS expense major maintenance costs as incurred. Concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with Florida Public Service Commission (FPSC) and Federal Energy Regulatory Commission (FERC) regulations.

 

Allowance for Funds Used During Construction (AFUDC)

 

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. The rate was 7.79% for 2003, 2002 and 2001. Total AFUDC for 2003, 2002 and 2001 was $27.4 million, $34.5 million, and $9.2 million, respectively. The base on which AFUDC is calculated excludes construction work-in-progress which has been included in rate base.

 

Deferred Income Taxes

 

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

 

Investment Tax Credits

 

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

 

Revenue Recognition

 

Tampa Electric Company recognizes revenues consistent with the Securities and Exchange Commission’s Staff Accounting Bulleting (SAB) 104, Revenue Recognition in Financial Statements. The interpretive criteria outlined in SAB 104 are that 1) there is persuasive evidence that an arrangement exists; 2) delivery has occurred or services have been rendered; 3) the fee is fixed and determinable; and 4) collectibility is reasonably assured. Except as discussed below, Tampa Electric Company recognizes revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer.

 

The regulated utilities’ (Tampa Electric and Peoples Gas System) retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by FERC. See Note 3 for a discussion of significant regulatory matters and the applicability of Financial Accounting Standard No. (FAS) 71, Accounting for the Effects of Certain Types of Regulation, to the company.

 

Revenues and Fuel Costs

 

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

 

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide a closer matching of revenues and expenses. See Note 3.

 

As of Dec. 31, 2003 and 2002, unbilled revenues of $45.7 million and $41.3 million, respectively, are included in the “receivables” line item on the balance sheet.

 

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Purchased Power

 

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. As a result of the sale of Hardee Power Partners, Ltd. (HPP) in October 2003 (see Notes 14 and 21 to the TECO Energy Consolidated Financial Statements in the 2003 Annual Report), subsequent power purchases from HPP are reflected as non-affiliate purchases by Tampa Electric. Tampa Electric’s long-term power purchase agreement from HPP was not affected by TPS’ sale of HPP. Under the existing agreement, which has been approved by the FERC and FPSC, Tampa Electric has the right to purchase, on average, approximately 52% of the total output of the Hardee power station. Tampa Electric purchased power from non-TECO Energy affiliates, including HPP, at a cost of $234.9 million, $253.7 million, and $209.7 million, respectively, for the years ended Dec. 31, 2003, 2002 and 2001. These purchased power costs are recoverable through an FPSC-approved cost recovery clause.

 

Depreciation

 

Tampa Electric provides for depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage value, of depreciable property over its estimated service life. The provision for utility plant in service, expressed as a percentage of the original cost of depreciable property was 4.6% for 2003 and 4.2% for 2002 and 2001. For the year ended Dec. 31, 2003, Tampa Electric recognized depreciation expense of $36.6 million related to accelerated depreciation of certain Gannon power station coal-fired assets, in accordance with a regulatory order issued by the FPSC. Construction work-in-progress is not depreciated until the asset is completed or placed in service.

 

The implementation of FAS 143, Accounting for Asset Retirement Obligations in 2003 resulted in an increase in the carrying amount of long-lived assets and the reclassification of the accumulated reserve for cost of removal from accumulated depreciation to “Regulatory liabilities,” for all periods presented. The adjusted capitalized amount is depreciated over the remaining useful life of the asset (see Note 4).

 

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

 

Tampa Electric Company is allowed to recover certain costs incurred from customers through prices approved by the regulatory process. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Statements of Income. These amounts totaled $77.7 million, $73.8 million and $71.7 million, for the years ended Dec. 31, 2003, 2002 and 2001, respectively. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. For the years ended Dec. 31, 2003, 2002 and 2001, these totaled $77.5 million, $73.7 million and $71.0 million, respectively.

 

Excise taxes paid by the regulated utilities are not material and are expenses when incurred.

 

Asset Impairments

 

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

 

In accordance with FAS 144, the company assesses whether there has been impairment of its long-lived assets and certain intangibles held and used by the company when such impairment indicators exist. Indicators of impairment existed for certain long-term turbine purchase contracts, triggering a requirement to ascertain the recoverability of these assets using undiscounted cash flows before interest expense. See Note 7 for specific details regarding the results of these assessments.

 

Restrictions on Dividend Payments and Transfer of Assets

 

Tampa Electric’s first mortgage bond indenture and certain long-term debt at PGS contain restrictions that limit the payment of dividends and distributions on the common stock of Tampa Electric Company. Tampa Electric’s first mortgage bond indenture does not limit loans or advances. As of Dec. 31, 2003 and 2002, the balances restricted as to transfers from Tampa Electric to TECO Energy under the first mortgage bonds were 3% and 20%, respectively, of consolidated common equity. Tampa Electric’s new credit facilities include a covenant limiting cumulative distributions and outstanding affiliate loans.

 

See Notes 5 and 14 for a more detailed description of significant financial covenants.

 

2. Derivatives and Hedging

 

From time to time, Tampa Electric Company enters into futures, forwards, swaps and option contracts to limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations.

 

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

 

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

 

Effective Jan. 1, 2001, the company adopted FAS 133, Accounting for Derivative Instruments and Hedging Activities. The new standard requires companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those

 

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instruments at fair value, and to reflect the changes in the fair value of those instruments as either components of other comprehensive income (OCI) or in net income, depending on the designation of those instruments. The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or the loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of its reclassification. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the amount paid or received on the underlying physical transaction. Additionally, amounts deferred in OCI related to an effective designated cash flow hedge must be reclassified to current earnings if the anticipated hedged transaction is no longer probable of occurring.

 

At Dec. 31, 2003 and 2002, respectively, the company had derivatives assets of $4.8 million and $3.5 million. The amounts recorded in accumulated other comprehensive income (OCI), as of Dec. 31, 2003 and 2002, are fully offset by regulatory assets or liabilities to reflect the impact of the fuel recovery clause on the results of hedging activities.

 

For the years ended Dec. 31, 2003, 2002 and 2001, Tampa Electric Company reclassified from OCI to earnings, pre-tax gains (losses) of $3.2 million, $0.2 million and $(0.7) million, respectively. Amounts reclassified were primarily related to cash flow hedges of physical purchases of natural gas. For these types of hedge relationships, the gain or loss on the derivative, reclassified from OCI to earnings, is offset by a regulatory asset or liability, reflecting the fact that all fuel hedging activity is subject to the fuel recovery clause (see Note 3).

 

Based on the fair values of derivatives at Dec. 31, 2003, pre-tax gains of $4.8 million are expected to be reversed from OCI to the Consolidated Statements of Income within the next twelve months. However, these gains and other future reclassifications from OCI will fluctuate with movements in the underlying market price of the derivative instruments. The company does not currently have any cash flow hedges for transactions forecasted to take place in periods subsequent to 2004.

 

3. Regulatory

 

As discussed in Note 1, Tampa Electric’s and PGS’ retail business are regulated by the FPSC.

 

Base Rate – Tampa Electric

 

Since the expiration, in 1999, of agreements entered into in 1996 with Florida’s Office of Public Counsel (OPC) and the Florida Industrial Power Users Group (FIPUG), which were approved by the FPSC, Tampa Electric is not under a new stipulation to stabilize prices while securing fair earnings opportunities. Tampa Electric’s rates and allowed return on equity (ROE) range of 10.75 percent to 12.75 percent with a midpoint of 11.75 percent are in effect until such time as changes are occasioned by an agreement approved by the FPSC or other PFSC actions as a result of rate other proceedings initiated by Tampa Electric, FPSC staff or other interest parties. Tampa Electric expects to continue earnings within its allowed ROE range.

 

Tampa Electric has not sought a base rate increase to recover the investment in the Bayside Power Station, of which phase one entered service in April 2003.

 

Cost Recovery – Tampa Electric

 

2003 Proceedings

 

In February 2003, Tampa Electric filed a request for an additional fuel cost adjustment of almost $61 million due to continued increases in the cost of natural gas and oil and the plan to phase out Gannon Units 1 through 4 in 2003. In March 2003, the FPSC approved Tampa Electric’s new fuel rates as well as new fuel rates for the other peninsular Florida investor-owned utilities.

 

In September 2003, 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 2004. In November, the FPSC approved Tampa Electric’s requested changes except for the lower coal transportation rate as a results of a new contract with TECO Transport described below. The resulting rates include the impacts of increased use of natural gas at the Bayside Power Station and the collection of $91 million for under recovery of fuel expense for 2002 and 2003. The filing also included estimated waterborne transportation rates for coal transportation services (see Note 12). The FPSC did not allow the recovery of $8.4 million it characterized as savings from shutting down the Gannon Station earlier than originally planned which the FPSC deemed generated operations and maintenance savings. The rates include projected costs associated with environmental projects required under the Florida Department of Environmental Protection (FDEP) Consent Final Judgment (see Note 14 for additional details regarding these environmental matters). The costs associated with this disallowance were recognized in 2003.

 

Tampa Electric filed its objection to the disallowance of the recovery of the $8.4 million and a motion asking FPSC to reconsider its decision because all facts and law were not taken into account. The motion was filed on Jan. 6, 2004, and a decision on this matter is expected in the first quarter of 2004. See Regulation – Cost Recovery Clauses section of MD&A.

 

As part of the regulatory process, it is reasonably likely that third parties may intervene on this or similar matters in the future. The company is unable to predict the timing, nature or impact of such future actions.

 

Base Rate – Peoples Gas

 

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

 

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

 

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Cost Recovery – Peoples Gas

 

In November 2003, the FPSC approved rates under Peoples’ Gas Purchased Gas Adjustment (PGA) cap factor for the period January 2004 through December 2004. The PGA is a factor that can vary monthly due to changes in actual fuel costs but is not anticipated to exceed the annual cap.

 

Other Items

 

Coal Transportation Contract

 

Tampa Electric’s contract for coal transportation and storage services with TECO Transport expired on Dec. 31, 2003. In June 2003, Tampa Electric issued a Request For Proposal (RFP) to potential providers requesting services for the next five years. The result of the RFP process was the execution of a new contract between Tampa Electric and TECO Transport with market rates supported by the results of the RFP and an independent expert in maritime transportation matters. The prudence of the RFP process and final contract is expected to be reviewed by the FPSC in May 2004, with a decision expected in July 2004.

 

Regional Transmission Organization (RTO)

 

In October 2002, the RTO process involving the proposed formation of GridFlorida, LLC, as initiated in response to the Federal Regulatory Commission’s (FERC’s) continuing effort to affect open access to transmission facilities in large regional markets, was delayed when the OPC filed an appeal with the Florida Supreme Court asserting that the FPSC could not relinquish its jurisdictional responsibility to regulate the IOUs and the approval of GridFlorida would result in such a relinquishment. 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. The FPSC has scheduled a series of collaborative meetings with all interested parties upon their conclusion, will set items for hearing and a hearing schedule. This is expected to occur throughout 2004.

 

Regulatory Assets and Liabilities

 

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

 

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Tampa Electric and PGS apply the accounting treatment permitted by FAS 71, Accounting for the Effects of Certain Types of Regulation. Areas of applicability include deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel; purchased power, conservation and environmental costs; and deferral of costs as regulatory assets when cost recovery is ordered over a period longer than a fiscal year, to the period that the regulatory agency recognizes them. Details of the regulatory assets and liabilities as of Dec. 31, 2003 and 2002 are presented in the following table:

 

Regulatory Assets and Liabilities (millions)

 

Dec. 31,


   2003

   2002

Regulatory assets:

             

Regulatory tax asset (1)

   $ 63.3    $ 54.9

Other:

             

Cost recovery clauses

     59.7      34.7

Coal contract buy-out (2)

     2.7      5.4

Deferred bond refinancing costs (3)

     32.2      35.9

Environmental remediation

     20.7      20.3

Competitive rate adjustment

     5.3      7.4

Other

     4.4      4.6
    

  

       125.0      108.3
    

  

Total regulatory assets

   $ 188.3    $ 163.2
    

  

Regulatory liabilities:

             

Regulatory tax liability (1)

   $ 29.9    $ 36.6

Other:

             

Deferred allowance auction credits

     1.9      2.1

Recovery clause related

     —        2.2

Environmental remediation

     20.7      20.3

Transmission and distribution storm reserve

     40.0      36.0

Deferred gain on property sales (4)

     1.9      0.9

Accumulated reserve – cost of removal

     462.2      440.6

Other

     3.6      —  
    

  

       530.3      502.1
    

  

Total regulatory liabilities

   $ 560.2    $ 538.7
    

  

 

(1) Related primarily to plant life. Includes excess deferred taxes of $17.0 million and $20.9 million as of Dec. 31, 2003 and 2002, respectively.

 

(2) Amortized over a 10-year period ending December 2004.

 

(3) Unamortized refinancing costs:

 

Related to debt transactions as follows (millions):


 

Amortized until:


$  50.0

  2004

$  51.6

  2005

$  22.1

  2007

$  25.0

  2011

$  50.0

  2011

$150.0

  2012

$150.0

  2012

$  85.9

  2014

$  25.0

  2021

$100.0

  2022

 

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

 

4. Asset Retirement Obligations

 

On Jan. 1, 2003, Tampa Electric Company adopted FAS 143, Accounting for Asset Retirement Obligations. The company recognized liabilities for retirement obligations associated with certain long-lived assets, in accordance with the relevant accounting guidance. An asset retirement obligation for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under an existing or enacted law or statute, a written or oral contract, or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.

 

When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The liability must be revalued each period based on current market prices.

 

As a result of the adoption of FAS 143, Tampa Electric Company recorded an increase to net property, plant and equipment of $0.1 million (net of accumulated depreciation), an increase in regulatory assets of $0.2 million, and an increase to asset retirement obligations of $0.3 million. The after-tax charge recorded as a change in accounting principle was not material.

 

For year ended Dec. 31, 2003, accretion expense associated with asset retirement obligations for Tampa Electric Company was not material. During this period, no new retirement obligations were incurred and no significant revisions to estimated cash flows used in determining the recognized asset retirement obligations were necessary. FAS 143 was not effective for years ended Dec. 31, 2002 and 2001.

 

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As regulated utilities, Tampa Electric and PGS must file depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components – a salvage factor and a cost of removal or dismantlement factor. The company uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation.

 

Upon adoption of FAS 143 at Jan. 1, 2003, the estimated accumulated cost of removal and dismantlement included in net accumulated depreciation at Dec. 31, 2003 and 2002 of $462.2 million and $440.6 million, respectively, was reclassified to a regulatory liability for all period presented (see also Note 3). For Tampa Electric and PGS, the original cost of utility plant retired or otherwise disposed of and the cost of removal, or dismantlement, less salvage value are charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively.

 

5. Short-Term Debt

 

At Dec. 31, 2003 and 2002, the following credit facilities and related borrowings existed:

 

Credit Facilities    Dec. 31, 2003

   Dec. 31, 2002

(millions)


   Credit
Facilities


   Borrowings
Outstanding


   Letters of
Credit
Outstanding


   Credit
Facilities


   Borrowings
Outstanding


   Letters of
Credit
Outstanding


Recourse:

                                         

Tampa Electric:

                                         

1-year facility

   $ 125.0    $ —      $ —      $ 300.0    $ —      $ —  

3-year facility

     125.0      —        —        —        —        —  
    

  

  

  

  

  

Total

   $ 250.0    $ —      $ —      $ 300.0    $ —      $ —  
    

  

  

  

  

  

 

The credit facility requirements commitment fees of 20 basis points, and drawn amounts are charged interest at LIBOR 105-117.5 basis points, depending upon the amount of the draw, at current ratings. Notes payable at Dec. 31, 2002 consisted of $10.5 million of commercial paper with a weighted average interest rate of 1.86%. There were no notes payables at Dec. 31, 2003.

 

On Nov. 7, 2003, Tampa Electric replaced its maturing $300 million credit facility with a $125 million one-year credit facility and a $125 million three-year credit facility, maturing in November 2004 and November 2006, respectively. In addition to the financial covenants described below and in Notes 1 and 14, the two new facilities include a covenant limiting cumulative distributions after Oct. 31, 2003 and outstanding loans to its parent to an amount representing an accumulation of net income after May 31, 2003 and capital contributions from the parent after Oct. 31, 2003, plus $450 million.

 

6. Common Stock

 

Tampa Electric Company is a wholly owned subsidiary of TECO Energy, Inc.

 

     Common Stock

   

Issue

Expense


       

(millions, except per share amounts)


   Shares

   Amount

      Total

 

Balance Dec. 31, 2000

   10    $ 1,148.8     $ (0.7 )   $ 1,148.1  

Contributed capital from parent

   —        170.0       —         170.0  
    
  


 


 


Balance Dec. 31, 2001

   10      1,318.8       (0.7 )     1,318.1  

Contributed capital from parent

   —        217.0       —         217.0  
    
  


 


 


Balance Dec. 31, 2002

   10      1,535.8       (0.7 )     1,535.1  

Contributed capital returned to parent

   —        (158.3 )     —         (158.3 )
    
  


 


 


Balance Dec. 31, 2003

   10    $ 1,377.5     $ (0.7 )   $ 1,376.8  
    
  


 


 


 

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7. Asset Impairments

 

In 2003, Tampa Electric Company recorded a $48.9 million after-tax charge ($79.6 million pre-tax) to reflect the impact of the cancellation of turbine purchase commitments. As reported previously and in Note 12, certain turbine rights had been transferred from Other Unregulated operations of TECO Energy to Tampa Electric in 2002 for use in Tampa Electric’s generation expansion activities. These cancellations, made in April 2003, fully terminate all turbine purchase obligations.

 

8. Restructuring Costs

 

In September and October of 2003, TECO Energy announced a corporate reorganization to restructure the company along functional lines, consistent with its objectives to grow the core utility operation, maintain liquidity, generate cash and maximize the value in the existing assets. As a result of these actions, TECO Energy is now aligned to provide for centralized oversight along functional lines for power plant operations, energy delivery, energy management, and human resources and technology/support services. The 2003 actions included the involuntary termination or retirement of 232 employees at Tampa Electric Company, including officers and other personnel from operations and support services.

 

In 2002, TECO Energy initiated a restructuring program that impacted approximately 182 employees at Tampa Electric. This program included retirements, the elimination of positions and other cost control measures. The total costs associated with this program included severance, salary continuation and other termination and retirement benefits.

 

Tampa Electric recognized a pre-tax expense of $14.0 million and $16.6 million for accrued benefits and other termination and retirement benefits for the years ended Dec. 31, 2003 and 2002, respectively. Tampa Electric Company completed these restructuring activities as of Dec. 31, 2003. As of Dec. 31, 2003 and 2002, respectively, no adjustments were made to the benefits initially accrued for and $8.4 million and $16.6 million, respectively, of the accrued benefits were paid or otherwise settled.

 

9. Income Tax Expense

 

Tampa Electric Company is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. Tampa Electric Company’s income tax expense is based upon a separate return computation. Income tax expense consists of the following components:

 

Income Tax Expense

 

(millions)


   Federal

    State

    Total

 

2003

                        

Currently payable

   $ 74.9     $ 17.6     $ 92.5  

Deferred

     (16.0 )     (7.9 )     (23.9 )

Amortization of investment tax credits

     (4.6 )     —         (4.6 )
    


 


 


Total income tax expense

   $ 54.3     $ 9.7       64.0  
    


 


 


Included in other income, net

                     (30.0 )
    


 


 


Included in operating expenses

                   $ 94.0  
    


 


 


2002

                        

Currently payable

   $ 66.7     $ 14.9     $ 81.6  

Deferred

     23.2       0.4       23.6  

Amortization of investment tax credits

     (4.4 )     —         (4.4 )
    


 


 


Total income tax expense

   $ 85.5     $ 15.3       100.8  
    


 


 


Included in other income, net

                     0.5  
    


 


 


Included in operating expenses

                   $ 100.3  
    


 


 


2001

                        

Currently payable

   $ 88.6     $ 15.7     $ 104.3  

Deferred

     (1.3 )     (0.7 )     (2.0 )

Amortization of investment tax credits

     (4.4 )     —         (4.4 )
    


 


 


Total income tax expense

   $ 82.8     $ 15.0       97.9  

Included in other income, net

                     0.2  
    


 


 


Included in operating expenses

                   $ 97.7  
    


 


 


 

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

 

Deferred Income Tax Assets and Liabilities

 

(millions) Dec. 31,


   2003

    2002

 

Deferred tax assets (1)

                

Property related

   $ 93.6     $ 90.3  

Leases

     3.1       3.5  

Insurance reserves

     20.5       17.7  

Early capacity payments

     3.5       6.0  

Other

     12.8       15.8  
    


 


Total deferred income tax assets

     133.5       133.3  
    


 


Deferred income tax liabilities (1)

                

Property related

     (500.0 )     (502.8 )

Other

     25.5       19.7  
    


 


Total deferred income tax liabilities

     (474.5 )     (483.1 )
    


 


Accumulated deferred income taxes

   $ (341.0 )   $ (349.8 )
    


 


 

(1) Certain property related assets and liabilities have been netted.

 

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

 

Effective Income Tax Rate

 

(millions)


   2003

    2002

    2001

 

Net income (1)

   $ 123.4     $ 196.0     $ 177.1  

Total income tax provision (1)

     64.0       100.8       97.9  
    


 


 


Income before income taxes (1)

   $ 187.4     $ 296.8     $ 275.0  
    


 


 


Income taxes on above at federal statutory rate of 35%

   $ 65.6     $ 103.8     $ 96.2  

Increase (decrease) due to

                        

State income tax, net of federal income tax

     6.3       10.0       9.8  

Amortization of investment tax credits

     (4.6 )     (4.4 )     (4.5 )

Equity portion of AFUDC

     (7.0 )     (8.7 )     (2.3 )

Other

     3.7       0.1       (1.3 )
    


 


 


Total income tax provision

   $ 64.0     $ 100.8     $ 97.9  
    


 


 


Provision for income taxes as a percent of income before income taxes

     34.2 %     34.0 %     35.6 %
    


 


 


 

(1) Includes $48.9 million after-tax ($79.6 million pre-tax) charges associated with cancellation of turbine purchase commitments noted above.

 

10. Other Comprehensive Income

 

Tampa Electric Company reported the following comprehensive income (loss) for the years ended Dec. 31, 2003, 2002 and 2001 related to changes in the fair value of cash flow hedges:

 

Comprehensive income (loss)

(millions)


   Gross

    Tax

    Net

 

2003

                        

Unrealized gain on cash flow hedges

   $ 3.2     $ 1.2     $ 2.0  

Less: Gain reclassified to net income

     (3.2 )     (1.2 )     (2.0 )
    


 


 


Total other comprehensive income (loss)

   $ —       $ —       $ —    
    


 


 


2002

                        

Unrealized gain on cash flow hedges

   $ 0.3     $ 0.1     $ 0.2  

Less: Gain reclassified to net income

     (0.2 )     (0.1 )     (0.1 )
    


 


 


Total other comprehensive income (loss)

   $ 0.1     $ —       $ 0.1  
    


 


 


2001

                        

Unrealized (loss) on cash flow hedges

   $ (0.8 )   $ (0.3 )   $ (0.5 )

Less: Loss reclassified to net income

     0.7       0.3       0.4  
    


 


 


Total other comprehensive income (loss)

   $ (0.1 )   $ —       $ (0.1 )
    


 


 


 

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11. Employee Postretirement Benefits

 

Pension Benefits

 

Tampa Electric Company is a participant in the comprehensive retirement plans of TECO Energy (multi-employer plans), including a non-contributory defined benefit retirement plan which covers substantially all employees. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses allocable to Tampa Electric Company are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy retirement plans. Benefits are based on employees’ age, years of service and final average earnings. On Apr. 1, 2000, the plan was amended to provide for benefits to be earned and payable substantially on a lump sum basis through an age and service credit schedule for eligible participants leaving the company on or after July 1, 2001. Other significant provisions of the plan, such as eligibility, definitions of credited service, final average earnings, etc., were largely unchanged. This amendment resulted in decreased pension expense at TECO Energy of approximately $0.8 million in 2001 and a reduction of benefit obligation of $6.2 million at Sept. 30, 2001.

 

TECO Energy’s policy is to fund the plan within the guidelines set by ERISA for the minimum annual contribution and the maximum allowable as a tax deduction by the IRS. In 2004, TECO Energy expects to make a contribution of about $14.2 million, of which Tampa Electric Company’s portion is expected to be about $9.1 million.

 

Amounts disclosed for pension benefits also include the unfunded obligations for the supplemental executive retirement plan, non-qualified, non-contributory defined benefit retirement plans available to certain senior management. In 2004, TECO Energy expects to make a contribution of about $1.7 million to these plans. TECO Energy reported other comprehensive loss of $43.9 million and $4.4 million in 2003 and 2002, respectively and other comprehensive income of $0.3 million in 2001 related to adjustments to the minimum pension liability associated with the supplemental executive retirement plan.

 

The asset allocation for the company’s pension plan as of Sept. 30, 2003 and 2002, and the target allocation for 2004, by asset category, follows:

 

Asset Allocation

 

    

Target

Allocation of

2004


  

Percentage of Plan Assets

at Sept. 30,


 

Asset category


      2003

    2002

 

Equities

   55% – 60%    57 %   53 %

Fixed income

   40% – 45%    43 %   47 %

Real Estate

      —       —    

Other

      —       —    
    
  

 

Total

      100 %   100 %
    
  

 

 

TECO Energy’s investment objective is to obtain above average returns while minimizing volatility of expected returns over the long term. The target equities/fixed income mix is designed to meet investment objectives. TECO Energy’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expense.

 

The assumptions for the expected return on plan assets were developed based on an analysis of historical market returns, the plan’s past experience and current market conditions. Estimates of future market returns are lower than actual long-term historical returns of the plan but were factored into the expected return on asset assumptions to generate a conservative forecast.

 

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

 

Components of net pension expense, reconciliation of the funded status and the accrued pension liability are presented below for TECO Energy consolidated.

 

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Pension Benefit Expense

 

(millions)


   2003

    2002

    2001

 

Components of net periodic benefit expense

                        

Service cost (benefits earned during the period)

   $ 14.3     $ 11.8     $ 11.2  

Interest cost on projected benefit obligations

     30.8       28.7       27.9  

Expected return on assets

     (42.1 )     (42.9 )     (42.0 )

Amortization of:

                        

Transition obligation (asset)

     (1.1 )     (1.1 )     (1.1 )

Prior service cost (benefit)

     (0.5 )     (0.5 )     (0.5 )

Actuarial (gain) loss

     1.4       (3.7 )     (4.4 )
    


 


 


Pension expense (benefit)

     2.8       (7.7 )     (8.9 )

Special termination benefit charge

     —         2.7       —    

Additional amounts recognized

     —         —         —    
    


 


 


Net pension expense (benefit) recognized in the

                        

TECO Energy Consolidated Statements of Income(1)

   $ 2.8     $ (5.0 )   $ (8.9 )
    


 


 


Assumptions used to determine net costs

                        

Discount rate

     6.75 %     7.50 %     7.50 %

Rate of compensation increase

     4.82 %     4.66 %     4.69 %

Expected return on plan assets

     9.00 %     9.00 %     9.00 %
    


 


 


 

(1) Tampa Electric Company’s portion was $(1.9) million, ($7.8) million and ($10.4) million for 2003, 2002 and 2001, respectively.

 

The following table shows the funded status of the qualified and non-qualified pension plans for which the projected obligation exceeds the fair value to the plan assets:

 

Pension Plans – Projected Obligation Exceeds Plan Assets

 

(millions) Dec. 31,


   2003

   2002

Projected benefit obligation

   $ 554.5    $ 455.1

Fair value of plan assets

     391.8      371.9
    

  

Projected obligation in excess of plan assets

   $ 162.7    $ 83.2
    

  

Accumulated benefit obligation

   $ 480.0    $ 400.8
    

  

 

As of Dec. 31, 2003, for the qualified and non-qualified pension plans, the accumulated obligation exceeded the fair value of the plan assets. As of Dec. 31, 2002, the accumulated obligation exceeded the fair value of the plan assets for only the non-qualified pension plan. The table below shows the funded status at the end of 2003 and 2002 for the respective plans:

 

Pension Plans – Accumulated Obligation Exceeds Plan Assets

 

(millions) Dec. 31,


   2003

   2002(1)

Projected benefit obligation

   $ 480.0    $ 32.8

Fair value of plan assets

     391.8      —  
    

  

Accumulated obligation in excess of plan assets

   $ 88.2    $ 32.8
    

  

Accumulated benefit obligation

   $ 554.5    $ 41.3
    

  

 

(1) In 2002 only the non-qualified plan is presented due to the fact that the fair value of plan assets exceeded the accumulated obligation for the qualified plan.

 

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Table of Contents

Reconciliation of the funded status of the retirement plan and the accrued pension prepayment/(liability)

 

(millions)


   2003

    2002

 

Change in benefit obligation

                

Net benefit obligation at prior measurement date

   $ 455.1     $ 382.3  

Service cost

     14.3       11.8  

Interest cost

     30.8       28.7  

Actuarial loss

     89.7       58.3  

Plan amendments

     —         1.1  

Special termination benefits

     —         2.7  

Curtailment

     (1.9 )     —    

Gross benefits paid

     (33.5 )     (29.8 )
    


 


Net benefit obligation at measurement date

   $ 554.5     $ 455.1  
    


 


Change in plan assets

                

Fair value of plan assets at prior measurement date

   $ 371.9     $ 428.0  

Actual return on plan assets

     51.7       (24.9 )

Employer contributions

     1.7       1.7  

Gross benefits paid (including expenses)

     (33.5 )     (32.9 )
    


 


Fair value of plan assets at measurement date

   $ 391.8     $ 371.9  
    


 


Funded status

                

Fair value of plan assets

   $ 391.8     $ 371.9  

Benefit obligation

     554.5       455.1  
    


 


Funded status at measurement date

     (162.7 )     (83.2 )

Net contributions after measurement date

     6.7       0.4  

Unrecognized net actuarial loss

     165.6       88.9  

Unrecognized prior service cost (benefit)

     (6.9 )     (7.4 )

Unrecognized net transition obligation (asset)

     (1.4 )     (2.5 )
    


 


Accrued liability at end of year

   $ 1.3     $ (3.8 )
    


 


Amounts recognized in the statement of financial position

                

Prepaid benefit cost

   $ 16.9     $ 14.8  

Accrued benefit cost

     (15.7 )     (18.5 )

Additional minimum liability

     (82.7 )     (13.8 )

Intangible asset

     1.3       1.5  

Accumulated other comprehensive income

     81.5       12.2  
    


 


Net amount recognized at end of year

   $ 1.3     $ (3.8 )
    


 


Assumptions used in determining actuarial valuations

                

Discount rate to determine projected benefit obligation

     6.00 %     6.75 %

Rate of increase in compensation levels

     4.25 %     9.0 %
    


 


 

Other Postretirement Benefits

 

Tampa Electric provides certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 meeting certain service requirements. The company contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and June 30, 2001 is limited to a defined dollar benefit based on years of service. On April 1, 2000, the company adopted changes to this program for participants retiring from the company on or after July 1, 2001. The company contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after July 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. The impact of this amendment, including a change in the company’s commitment for future retirees combined with a grandfathering provision for current retired participants, resulted in a reduction in the benefit obligation of $1.4 million in 2001. In 2004, TECO Energy expects to make a contribution of about $9.5 million to this program. Postretirement benefit levels are substantially unrelated to salary. The company reserves the right to terminate or modify the plans in whole or in part at any time.

 

On Dec. 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). Beginning in 2006, the new law adds prescription drug coverage to Medicare, with a 28% tax-free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. TECO Energy’s current retiree medical program for those eligible for Medicare (generally over age 65) includes coverage for prescription drugs. The company is continuing to analyze the potential impact the Act may have on the company’s FAS 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, expense and what, if any, plan design changes should be made with respect to the company’s retiree medical program in response to the Act.

 

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Table of Contents

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

 

Other Postretirement Benefit Expense

 

(millions)


   2003

   2002

    2001

Components of net periodic benefit expense

                     

Service cost (benefits earned during the period)

   $ 2.6    $ 2.4     $ 2.3

Interest cost on projected benefit obligations

     9.3      8.6       8.4

Amortization of:

                     

Transition obligation (straight line over 20 years)

     2.1      2.1       2.1

Prior service cost

     1.7      1.7       1.7

Actuarial loss

     1.0      0.1       0.3
    

  


 

Pension expense

     16.7      14.9       14.8

Special termination benefits

     —        0.6       —  

Additional amounts recognized

     0.1      (0.1 )     —  
    

  


 

Net periodic postretirement benefit expense

   $ 16.8    $ 15.4     $ 14.8
    

  


 

 

The accumulated postretirement benefit obligation exceeds plan assets for the postretirement health and welfare benefits plan.

 

Reconciliation of the funded status of the postretirement benefit plan and the accrued liability

 

(millions)


   2003

    2002

 

Change in benefit obligation

                

Net benefit obligation at prior measurement date

   $ 138.8     $ 114.8  

Service cost

     2.6       2.4  

Interest cost

     9.3       8.6  

Plan participants’ contributions

     1.0       0.8  

Actuarial loss

     3.1       17.3  

Special termination benefits

     —         0.6  

Gross benefits paid

     (8.0 )     (5.7 )
    


 


Net benefit obligation at measurement date

   $ 146.8     $ 138.8  
    


 


Change in plan assets

                

Fair value of plan assets at prior measurement date

     —         —    

Employer contributions

     7.0       4.9  

Plan participants contributions

     1.0       0.8  

Gross benefits paid (including expenses)

     (8.0 )     (5.7 )
    


 


Fair value of plan assets at measurement date

   $ —       $ —    
    


 


Funded status

                

Funded status at measurement date

   $ (146.8 )   $ (138.8 )

Net contributions after measurement date

     1.8       1.5  

Unrecognized net actuarial loss

     31.5       29.5  

Unrecognized prior service cost

     18.7       20.3  

Unrecognized net transition obligation

     19.0       21.1  
    


 


Accrued liability at end of year

   $ (75.8 )   $ (66.4 )
    


 


Assumptions Used in Determining Actuarial Valuations

                

Discount rate to determine projected benefit obligation

     6.00 %     6.75 %
    


 


 

Employer contributions and benefits paid in the above tables include both those amounts contributed directly to, and paid directly from both plan assets and directly to plan participants. The assumed health care cost trend rate for medical costs was 11.5% in 2003 and decreases to 5.0% in 2013 and thereafter.

 

A 100 basis point increase in the medical trend rates would produce a 3 percent ($0.4 million) increase in the aggregate service and interest cost for 2003, and a 4 percent ($5.4 million) increase in the accumulated postretirement benefit obligation as of Sept. 30, 2003.

 

A 100 basis point decrease in the medical trend rates would produce a 2 percent ($0.3 million) decrease in the aggregate service and interest cost for 2003 and a 2 percent ($3.5 million) decrease in the accumulated postretirement benefit obligation as of Sept. 30, 2003.

 

12. Related Party Transactions

 

In February 2002, Tampa Electric and TECO-Panda Generating Company (TPGC) II, an affiliate of TECO Wholesale Generation, entered into an assignment and assumption agreement under which Tampa Electric obtained TPGC II’s rights and interests to four combustion turbines being purchased from General Electric, and assumed the corresponding liabilities and obligations for such equipment. In accordance with the terms of the assignment and assumption agreement, Tampa Electric paid $62.5 million to TPGC II as reimbursement

 

45


Table of Contents

for amounts already paid to General Electric by TPGC II for such equipment. No gain or loss was incurred on the transfer. In the first quarter of 2003, Tampa Electric recorded a $48.9 million after-tax charge related to the cancellation of these turbine purchase commitments (see Note 7).

 

In the second and third quarters of 2003, Tampa Electric returned approximately $158 million of capital to TECO Energy. TECO Energy had previously contributed capital to Tampa Electric in support of Tampa Electric’s construction program in the wholesale business, which was subsequently scaled back.

 

In October 2003, Tampa Electric signed a five-year contract renewal with a TECO Energy affiliate company, TECO Transport Corporation, for integrated waterborne fuel transportation services effective Jan. 1, 2004. The contract calls for inland river and ocean transportation along with river terminal storage and blending services for up to 5.5 million tons of coal annually through 2008. See Note 3 for additional details.

 

A summary of activities between Tampa Electric Company and its affiliates follows:

 

Net transactions with affiliates:

 

(millions)


   2003

   2002

   2001

Fuel and interchange related, net

   $ 152.4    $ 144.9    $ 162.0

Administrative and general, net

   $ 13.7    $ 10.7    $ 22.1
    

  

  

Amounts due from or to affiliates of the company at Dec. 31,

(millions)


   2003

   2002

    

Accounts receivable (1)

   $ 4.5    $ 6.6       

Accounts payable (1)

   $ 13.3    $ 23.6       
    

  

      

 

(1) Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest

 

13. Segment Information

 

Tampa Electric Company is a public utility operating within the state of Florida. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to more than 612,000 customers in West Central Florida. Its Peoples Gas System division is engaged in the purchase, distribution and marketing of natural gas for more than 299,000 residential, commercial, industrial and electric power generation customers in the state of Florida.

 

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Table of Contents

Segment Information

 

(millions)


   Tampa
Electric


    Peoples
Gas


   Other &
Eliminations


    Tampa
Electric
Company


 

2003

                               

Revenues – outsiders

   $ 1,582.7     $ 408.4    $ —       $ 1,991.1  

Sales to affiliates

     3.4       —        (0.7 )     2.7  
    


 

  


 


Total revenues

   $ 1,586.1     $ 408.4    $ (0.7 )   $ 1,993.8  

Depreciation

     210.3       32.7      —         243.0  

Restructuring costs(1)

     9.9       4.1      —         14.0  

Interest charge

     85.0       15.6      —         100.6  

Provision for taxes

     48.1 (2)     15.2      —         63.3 (2)

Net income

   $ 98.9     $ 24.5    $ —       $ 123.4  
    


 

  


 


Total assets

     4,191.3       651.5      (7.1 )     4,835.7  

Capital expenditures

   $ 289.1     $ 42.6    $ —       $ 331.7  
    


 

  


 


2002

                               

Revenues – outsiders

   $ 1,548.9     $ 318.1    $ —       $ 1,867.0  

Sales to affiliates

     34.3       —        (0.7 )     33.6  
    


 

  


 


Total revenues

   $ 1,583.2     $ 318.1    $ (0.7 )   $ 1,900.6  

Depreciation

     189.8       30.5      (0.2 )     220.1  

Restructuring costs(2)

     16.6       —        —         16.6  

Interest charge

     51.5       14.8      —         66.3  

Provision for taxes

     85.7       14.7      —         100.4  

Net income

   $ 171.8     $ 100.4    $ —       $ 196.0  
    


 

  


 


Total assets

     4,135.0       650.2      (6.9 )     4,778.3  

Capital expenditures

   $ 632.2     $ 53.4    $ —       $ 685.6  
    


 

  


 


2001

                               

Revenues – outsiders

   $ 1,380.1     $ 352.9    $ —       $ 1,733.0  

Sales to affiliates

     32.6       —        (0.9 )     31.7  
    


 

  


 


Total revenues

   $ 1,412.7     $ 352.9    $ (0.9 )   $ 1,764.7  

Depreciation

     173.4       27.9      —         201.3  

Restructuring costs

     —         —        —         —    

Interest charge

     60.8       14.3      —         75.1  

Provision for taxes

     83.5       14.2      —         97.7  

Net income

   $ 154.0     $ 23.1    $ —       $ 177.1  
    


 

  


 


Total assets

     3,693.0       605.0      (6.0 )     4,292.0  

Capital expenditures

   $ 426.3     $ 73.0    $ —       $ 499.3  
    


 

  


 


 

(1) See Note 8 for a discussion of restructuring charges in 2003 and 2002.

 

(2) Net income for 2003 includes a $48.9 million after-tax charge (79.6 million pre-tax) asset impairment charge related to the turbine purchase cancellations (see Note 7).

 

14. Commitments and Contingencies

 

Capital Investments

 

For 2004, Tampa Electric expects to spend $182.9 million, consisting of $9.4 million (committed as of Dec. 31, 2003) for the completion of the repowering project at the Gannon Station, $18.2 million for environmental expenditures and $155.3 million to support system growth and generation reliability. Tampa Electric’s estimated capital expenditures over the 2005-2008 period are projected to be $1,006.4 million, including $323.8 million for environmental expenditures.

 

Capital expenditures for PGS are expected to be about $40 million in 2004 and $160 million during the 2005-2008 period. Included in these amounts are approximately $25 million annually for projects associated with customer growth and system expansion. The remainder represents capital expenditures for ongoing maintenance and system safety.

 

Legal Contingencies

 

Three lawsuits have been filed in the Circuit Court in Hillsborough County against Tampa Electric, in connection with the location of transmission structures in certain residential areas, by residents in the areas surrounding the structures. The high-voltage power lines are needed by Tampa Electric to move electricity to the northwest part of its service territory where population growth has been experienced. The residents are seeking to remove the poles or to receive monetary damages. Tampa Electric is working with the community to determine the feasibility of alternate routes or structures or some combination.

 

From time to time Tampa Electric Company is involved in various other legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with FAS 5, Accounting for Contingencies, to provide for matters that are reasonably likely to result in an estimable, material loss. While the outcome of such proceedings is uncertain, management does not believe that the ultimate resolution of pending matters will have a material adverse effect on the company’s results of operations or financial condition.

 

Superfund and Former Manufactured Gas Plant Sites

 

Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a potentially responsible party for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Dec. 31, 2003, Tampa Electric Company has estimated its ultimate financial liability to be $20 million, and this amount has been accrued in the company’s financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

 

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Table of Contents

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

 

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.

 

Long Term Commitments

 

Tampa Electric Company has commitments under long-term operating leases, primarily for building space, office equipment and heavy equipment. Total rental expense included in the Consolidated Statements of Income for the years ended Dec. 31, 2003, 2002 and 2001 was $6.2 million, $6.1 million and $6.1 million, respectively. The following table is a schedule of future minimum lease payments at Dec. 31, 2003 for all operating leases with noncancelable lease terms in excess of one year:

 

Future Minimum Lease Payments for Operating Leases

 

Year ended Dec. 31:


   Amount (millions)

2004

   $ 4.6

2005

     4.6

2006

     4.1

2007

     2.5

2008

     0.3

Later Years

     0.2
    

Total minimum lease payments

   $ 16.3
    

 

In 1994, Tampa Electric bought out a long-term coal supply contract which would have expired in 2004 for a lump sum payment of $25.5 million. In February 1995, the FPSC authorized the recovery of this buy-out amount plus carrying costs through the Fuel and Purchase Power Cost Recovery Clause over the 10-year period beginning Apr. 1, 1995. In each of the years 2003, 2002 and 2001, $2.7 million of buy-out costs were amortized to expense.

 

Guarantees and Letters of Credit

 

On Jan. 1, 2003, Tampa Electric Company adopted the prospective initial measurement provisions for certain types of guarantees, in accordance with FASB Interpretation No. (FIN) 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34). Upon issuance or modification of a guarantee after Jan. 1, 2003, the company must determine if the obligation is subject to either or both of the following:

 

  Initial recognition and initial measurement of a liability; and/or

 

  Disclosure of specific details of the guarantee.

 

Generally, guarantees of the performance of a third party or guarantees that are based on an underlying (where such a guarantee is not a derivative subject to FAS 133) are likely to be subject to the recognition and measurement, as well as the disclosure provisions, of FIN 45. Such guarantees must initially be recorded at fair value, as determined in accordance with the interpretation.

 

Alternatively, guarantees between and on behalf of entities under common control or that are similar to product warranties are subject only to the disclosure provisions of the interpretation. The company must disclose information as to the term of the guarantee and the maximum potential amount of future gross payments (undiscounted) under the guarantee, even if the likelihood of a claim is remote.

 

As of Dec. 31, 2003, Tampa Electric Company had outstanding letters of credit of $0.9 million, which guarantee performance to third parties related to debt service.

 

Tampa Electric Company also enters into commercial agreements in the normal course of business that typically contain standard indemnification clauses. Tampa Electric Company may sometimes agree to make payments to compensate or indemnify the counterparty for legal fees, environmental remediation costs and other similar costs arising from possible future events or changes in laws or regulations. These agreements cover a variety of goods and services, and have varying triggering events dependent on actions by third parties.

 

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Tampa Electric Company is unable to estimate the maximum potential future exposure under these clauses because the events that would obligate Tampa Electric Company have not occurred, or if such event has occurred, Tampa Electric Company has not been notified of any occurrence. As claims are made or changes in laws or regulations indicate, an amount related to the indemnification is reflected in the financial statements.

 

Financial Covenants

 

A summary of Tampa Electric’s significant financial covenants is as follows:

 

Tampa Electric Significant Financial Covenants

 

(millions) Instrument


 

Financial Covenant (1)


 

Requirement/ Restriction


 

Calculation at Dec. 31, 2003


Tampa Electric

           

Mortgage bond indenture

  Dividend restriction  

Cumulative distributions cannot exceed cumulative net income plus $4

  $5 unrestricted(2)

PGS senior notes

 

EBIT/interest(3)

Restricted payments

Funded debt/capital

Sale of assets

 

Minimum of 2.0 times

Shareholder equity at least $500

Cannot exceed 65%

Less than 20% of total assets

 

3.5 times

$1,652

50.5%

—%

Credit facility

 

Debt/capital

EBITDA/interest (3)

Restriction on

     distributions

 

Cannot exceed 60%

Minimum of 2.5 times

Limit on cumulative distributions and outstanding affiliate loans(4)

 

49.2%

5.8 times

$483 unrestricted

6.25% senior notes

 

Debt/capital

Limit on liens

 

Cannot exceed 60%

Cannot exceed $787

 

49.2%

$362

 

(1) As defined in applicable instrument.

 

(2) Reflects the determination as of Dec. 31, 2003, after giving effect to $158 million distributed to TECO Energy as a return of capital during 2003. There were $75 million of callable bonds outstanding under the indenture at Dec. 31, 2003.

 

(3) EBIT generally represents earnings before interest and taxes. EBITDA generally represents EBIT before depreciation and amortization. However, in each circumstance, the term is subject to the definition prescribed under the relevant legal agreements.

 

(4) Limits cumulative distributions after Oct. 31, 2003 and outstanding affiliate loans to an amount representing an accumulation of net income after May 31, 2003 and capital contributions from the parent after Oct. 31, 2003, plus $450 million.

 

15. New Accounting Pronouncements

 

Amendment to Derivatives Accounting

 

In April 2003, the FASB issued FAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, which clarifies the definition of a derivative and modifies, as necessary, FAS 133 to reflect certain decisions made by the FASB as part of the Derivatives Implementation Group (DIG) process. The majority of the guidance was already effective and previously applied by the company in the course of the adoption of FAS 133.

 

In particular, FAS 149 incorporates the conclusions previously reached in 2001 under DIG Issue C10, “Can Option Contracts and Forward Contracts with Optionality Features Qualify for the Normal Purchases and Normal Sales Exception”, and DIG Issue C15, “Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity”. In limited circumstances, when the criteria are met and documented, Tampa Electric Company designates option-type and forward contracts in electricity as a normal purchase or normal sale (NPNS) exception to FAS 133. A contract designated and documented as qualifying for the NPNS exception is not subject to the measurement and recognition requirements of FAS 133. The incorporation of the conclusions reached under DIG Issues C10 and C15 into the standard will not have a material impact on the consolidated financial statements of Tampa Electric Company.

 

FAS 149 establishes multiple effective dates based on the source of the guidance. For all DIG Issues previously cleared by the FASB and not modified under FAS 149, the effective date of the issue remains the same. For all other aspects of the standard, the guidance is effective for all contracts entered into or modified after June 30, 2003. The company does not anticipate that the adoption of the additional guidance in FAS 149 will have a material impact on the consolidated financial statements.

 

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Financial Instruments with Characteristics of both Liabilities and Equity

 

In May 2003, the FASB issued FAS 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, which requires that an issuer classify certain financial instruments as a liability or an asset. Previously, many financial instruments with characteristics of both liabilities and equity were classified as equity. Financial instruments subject to FAS 150 include financial instruments with any of the following features:

 

  An unconditional redemption obligation at a specified or determinable date, or upon an event that is certain to occur;

 

  An obligation to repurchase shares, or indexed to such an obligation, and may require physical share or net cash settlement;

 

  An unconditional, or for new issuances conditional, obligation that may be settled by issuing a variable number of equity shares if either (a) a fixed monetary amount is known at inception, (b) the variability is indexed to something other than the fair value of the issuer’s equity shares, or (c) the variability moves inversely to changes in the fair value of the issuer’s shares.

 

The standard requires that all such instruments be classified as a liability, or an asset in certain circumstances, and initially measured at fair value. Forward contracts that require a fixed physical share settlement and mandatorily redeemable financial instruments must be subsequently re-measured at fair value on each reporting date.

 

This standard is effective for all financial instruments entered into or modified after May 31, 2003, and for all other financial instruments at the beginning of the first interim period beginning after June 15, 2003. The adoption of FAS 150 has had no material impact on the consolidated financial statements.

 

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Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

 

During the period Jan. 1, 2002 to the date of this report, neither TECO Energy nor Tampa Electric Company has had or has filed with the Commission a report as to any changes in or disagreements with accountants on accounting principles or practices, financial statement disclosure, or auditing scope or procedure.

 

Item 9A. CONTROLS AND PROCEDURES

 

TECO Energy, Inc.

 

(a) Evaluation of Disclosure Controls and Procedures. TECO Energy’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of TECO Energy’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this annual report (the “Evaluation Date”). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, TECO Energy’s disclosure controls and procedures are effective and designed to ensure that the information relating to TECO Energy (including its consolidated subsidiaries) required to be included in TECO Energy’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the requisite time periods.

 

(b) Changes in Internal Controls. There have not been any changes in TECO Energy’s internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, such controls.

 

Tampa Electric Company

 

(a) Evaluation of Disclosure Controls and Procedures. Tampa Electric Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of Tampa Electric’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, Tampa Electric’s disclosure controls and procedures are effective and designed to ensure that the information relating to Tampa Electric (including its consolidated subsidiaries) required to be included in Tampa Electric’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the requisite time periods.

 

(b) Changes in Internal Controls. There have not been any significant changes in Tampa Electric’s internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, such controls.

 

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PART III

 

Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

 

(a) The information required by Item 10 with respect to the directors of the registrant is included under the caption “Election of Directors” on pages 1 through 2 of TECO Energy’s definitive proxy statement, dated March 25, 2004, for its Annual Meeting of Shareholders to be held on April 28, 2004 (Proxy Statement) and is incorporated herein by reference.

 

(b) The information required by Item 10 concerning executive officers of the registrant is included under the caption “Executive Officers of the Registrant” on page 21 of this report.

 

(c) The information required by Item 10 concerning Section 16(a) Beneficial Ownership Reporting Compliance is included under that caption on page 20 of the Proxy Statement and is incorporated herein by reference.

 

(d) TECO Energy has had a code of ethics applicable to all of its employees and officers for many years. It was expanded to apply to the Board of Directors in 2002. The text of the Standards of Integrity is available on the company’s website at www.tecoenergy.com under Investor Relations. Any amendments to or waivers of the Standards of Integrity for the benefit of any executive officer or director will also be posted on the website.

 

(e) Information regarding TECO Energy’s Audit Committee is included on pages 3 and 19 of the Proxy Statement, and is incorporated herein by reference.

 

Item 11. EXECUTIVE COMPENSATION.

 

The information required by Item 11 is included in the Proxy Statement beginning on page 6 under that caption and ending on page 11 just above the caption “Approval of the 2004 Equity Incentive Plan”, and under the caption “Compensation of Directors” on page 3, and is incorporated herein by reference.

 

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

 

The information required by Item 12 is included under the caption “Share Ownership” on pages 4 and 5 of the Proxy Statement and under the caption “Equity Compensation Plan Information” on page 15 of the Proxy Statement, and is incorporated herein by reference.

 

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

 

The information required by Item 13 is included under the caption “Certain Relationships and Related Transactions” on page 4 of the Proxy Statement, and is incorporated herein by reference.

 

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.

 

The information required by Item 14 is included under the caption “Independent Public Accountants” on pages 19 and 20 of the Proxy Statement and is incorporated herein by reference.

 

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PART IV

 

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.

 

(a) Certain Documents Filed as Part of this Form 10-K

 

  1. Financial Statements

TECO Energy, Inc. Financial Statements – filed as part of Exhibit 13 of this report, and is hereby incorporated by reference.

Tampa Electric Company Financial Statements – See index on page 25

 

  2. Financial Statement Schedules

Condensed Parent Company Financial Statements Schedule I – pages 54 – 57

TECO Energy, Inc. Schedule II – page 58

Tampa Electric Company Schedule II – page 59

 

  3. Exhibits – See index beginning on page 63

 

(b) Reports on Form 8-K – in process

 

TECO Energy, Inc. filed or furnished the following reports on Form 8-K during the last quarter of 2003.

 

  1. Current Report on Form 8-K of Oct. 23, 2003, filing under “Item 5. Other Events”, to report TECO Energy, Inc.’s entering into on a Suspension Agreement in connection with TECO Energy’s Construction Undertaking Agreements (Construction Undertakings) and other guaranty agreements for the Union and Gila River projects, and furnishing under “Item 12. Results of Operations and Financial Condition”, TECO Energy’s unaudited financial results for the three-month and nine-month periods ending Sept. 30, 2003.

 

  2. Current Report on Form 8-K of Oct. 30, 2003, furnishing under “Item 12. Results of Operations and Financial Condition”, unaudited financial and other unaudited financial data for the three-month, nine-month and 12-month periods ended Sept. 30, 2003 and 2002, and non-GAAP earnings per share information.

 

TECO Energy, Inc. filed or furnished the following reports on Form 8-K subsequent to Dec. 31, 2003.

 

  1. Current Report on Form 8-K of Feb. 2, 2004, filing under “Item 5. Other Events”, to announce that TECO Energy the Union and Gila River project companies and the lending banks had entered into a standstill agreement through Feb. 5, 2004 relating to matters covered by the Suspension Agreement.

 

  2. Current Report on Form 8-K of Feb. 5, 2004, filing under “Item 5. Other Events”, to announce TECO Energy’s decision to exit from its ownership of the Union and Gila River projects and to cease further funding of these plants.

 

  3. Current Report on Form 8-K of Feb. 9, 2004, furnishing under “Item 12. Results of Operations and Financial Condition”, financial results for the three-month and twelve-month periods ended Dec. 31, 2003.

 

  4. Current Report on Form 8-K of Mar. 3, 2004, furnishing under “Item 12. Results of Operations and Financial Condition”, revised 2003 financial results for TECO Energy, Inc.

 

Tampa Electric Company did not file any reports on Form 8-K during or subsequent to the last quarter of 2003.

 

(c) The exhibits filed as part of this Form 10-K are listed on the Exhibit Index immediately preceding such Exhibits. The Exhibit Index is incorporated herein by reference.

 

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SCHEDULE I – CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

 

TECO ENERGY, INC.

PARENT COMPANY ONLY

Condensed Balance Sheets

 

(millions)             

Dec. 31,


   2003

    2002

 

Assets

                

Current assets

                

Cash and cash equivalents

   $ 28.0     $ 370.9  

Restricted cash

     6.9       —    

Advances to affiliates

     3,078.4       2,380.1  

Accounts receivable from affiliates

     3.4       —    

Other current assets

     11.4       13.0  
    


 


Total current assets

     3,128.1       2,764.0  
    


 


Other assets

                

Investment in subsidiaries

     1,381.5       2,646.2  

Deferred income taxes

     293.5       220.7  

Other assets

     46.7       46.3  
    


 


Total other assets

     1,721.7       2,913.2  
    


 


Total assets

   $ 4,849.8     $ 5,677.2  
    


 


Liabilities and capital

                

Current liabilities

                

Notes payable

   $ 37.5     $ 350.0  

Accounts payable to affiliates

     0.3       19.1  

Accounts payable

     21.9       32.3  

Interest payable

     19.2       21.4  

Other current liabilities

     9.1       4.5  
    


 


Total current liabilities

     88.0       427.3  
    


 


Other liabilities

                

Advances from affiliates

     233.9       221.0  

Deferred income taxes

     117.4       —    

Long-term debt

                

Junior subordinated

     669.3       669.3  

Others

     1,958.8       1,656.5  

Other liabilities

     104.7       91.4  
    


 


Total other liabilities

     3,084.1       2,638.2  
    


 


Capital

                

Common equity

     187.8       175.8  

Additional paid in capital

     1,220.8       1,094.5  

Retained earnings

     339.5       1,413.7  

Accumulated other comprehensive income

     (55.8 )     (41.2 )
    


 


Common equity

     1,692.3       2,642.8  

Unearned compensation

     (14.6 )     (31.1 )
    


 


Total capital

     1,677.7       2,611.7  
    


 


Total liabilities and capital

   $ 4,849.8     $ 5,677.2  
    


 


 

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

 

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SCHEDULE I – CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

 

TECO ENERGY, INC.

PARENT COMPANY ONLY

Condensed Statements of Income

 

(millions)

For the years ended Dec. 31,


   2003

    2002

    2001

 

Revenues

   $ 4.4     $ 6.7     $ 2.0  

Expenses

                        

Administrative and general expenses

     7.2       8.6       6.8  

Restructuring charges

     2.6       —         —    
    


 


 


Total expenses

     9.8       8.6       6.8  
    


 


 


Income from operations

     (5.4 )     (1.9 )     (4.8 )

Loss on debt extinguishment

     —         (34.1 )     —    

(Losses) earnings from investments in subsidiaries

     (873.2 )     363.8       308.7  

Interest income (expense)

                        

Interest income

                        

Affiliates

     139.3       120.0       72.9  

Interest expense

                        

Affiliates

     (43.0 )     (40.1 )     (17.5 )

Others

     (171.9 )     (103.4 )     (56.6 )
    


 


 


Total interest expense

     (75.6 )     (23.5 )     (1.2 )
    


 


 


(Loss) income before income taxes

     (954.2 )     304.3       302.7  

(Benefit) for income taxes

     (48.0 )     (25.8 )     (1.0 )
    


 


 


Net (loss) income from operations

     (906.2 )     330.1       303.7  

Cumulative effect of change in accounting principle, net of tax

     (3.2 )     —         —    
    


 


 


Net (loss) income

   $ (909.4 )   $ 330.1     $ 303.7  
    


 


 


 

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

 

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SCHEDULE I – CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

 

TECO ENERGY, INC.

PARENT COMPANY ONLY

Condensed Statements of Cash Flows

 

(millions)

For the years ended Dec. 31,


   2003

    2002

    2001

 

Cash flows from operating activities

   $ 10.2     $ (82.4 )   $ (128.0 )

Cash flows from investing activities

                        

Investment in subsidiaries

     156.7       (232.4 )     (408.2 )

Dividends from subsidiaries

     296.0       316.1       307.6  

Net change in affiliate advances

     (741.2 )     (1,230.8 )     (841.3 )
    


 


 


Cash flows from investing activities

     (288.5 )     (1,147.1 )     (941.9 )
    


 


 


Cash flows from financing activities

                        

Dividends to shareholders

     (165.2 )     (215.8 )     (184.2 )

Common stock

     136.6       572.6       348.4  

Proceeds from long-term debt – others

     296.8       1,510.9       1,012.2  

Repayment of long-term debt – others

     —         (600.0 )     (153.2 )

Net increase (decrease) in short-term debt

     (312.5 )     350.0       —    

Equity contract adjustment payments

     (20.3 )     (15.3 )     —    
    


 


 


Cash flows from financing activities