10-K 1 d10k.htm FORM 10-K Form 10-K

 

 

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, 2010

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) 228-1111  
1-5007   TAMPA ELECTRIC COMPANY   59-0475140
  (a Florida corporation)  
  TECO Plaza  
  702 N. Franklin Street  
  Tampa, Florida 33602  
  (813) 228-1111  

 

 

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

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

 

 

Indicate by check mark if TECO Energy, Inc. is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    YES  x    NO  ¨

Indicate by check mark if Tampa Electric Company is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     YES  ¨    NO  x

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.     YES  ¨    NO  x

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 whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).    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 amendment to this Form 10-K.  ¨

Indicate by check mark whether TECO Energy, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large Accelerated filer   x    Accelerated filer   ¨
Non-Accelerated filer   ¨    Smaller reporting company   ¨

Indicate by check mark whether Tampa Electric Company is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large Accelerated filer   ¨    Accelerated filer   ¨
Non-Accelerated filer   x    Smaller reporting company   ¨

Indicate by check mark whether TECO Energy, Inc. is a shell company (as defined in Rule 12b-2 of the Act).    YES  ¨    NO  x

Indicate by check mark whether Tampa Electric Company is a shell company (as defined in Rule 12b-2 of the Act).    YES  ¨    NO  x

The aggregate market value of TECO Energy, Inc.’s common stock held by non-affiliates of the registrant as of Jun. 30, 2010 was $3,233,787,526 based on the closing sale price as reported on the New York Stock Exchange.

The aggregate market value of Tampa Electric Company’s common stock held by non-affiliates of the registrant as of Jun. 30, 2010 was zero.

The number of shares of TECO Energy, Inc.’s common stock outstanding as of Feb. 21, 2011 was 214,890,426. As of Feb. 21, 2011, there were 10 shares of Tampa Electric Company’s common stock issued and outstanding, all of which were held, beneficially and of record, by TECO Energy, Inc.

 

 

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Definitive Proxy Statement relating to the 2011 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.

Cover page 1 of 191

Index to Exhibits begins on page E-1

 

 

 


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 approximately 4,233 employees as of Dec. 31, 2010.

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 Code of Ethics and Business Conduct, are available on the Investors section of TECO Energy’s website, www.tecoenergy.com, or in print free of charge to any investor who requests the information. TECO Energy also makes its Securities and Exchange Commission (SEC) (www.sec.gov) filings available free of charge on the Investors section of TECO Energy’s website as soon as reasonably practicable after they are filed with or furnished to the SEC.

TECO Energy is a holding company for regulated utilities and other businesses. TECO Energy currently owns no operating assets but holds all of the common stock of Tampa Electric Company and through its subsidiary TECO Diversified, Inc., owns TECO Coal Corporation and through its subsidiary TECO Wholesale Generation, Inc., owns TECO Guatemala, Inc.

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’s business segments and revenues for those segments, for the years indicated, are identified below.

Tampa Electric Company, a Florida corporation and TECO Energy’s largest subsidiary, has two business segments. Its Tampa Electric division (Tampa Electric) provides retail electric service to more than 672,000 customers in West Central Florida with a net winter system generating capability of 4,684 megawatts (MW). Peoples Gas System (PGS), the gas division of Tampa Electric Company, is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida. With more than 336,000 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 2010 was almost 1.6 billion therms.

TECO Coal Corporation (TECO Coal), a Kentucky corporation, has 11 subsidiaries located in Eastern Kentucky, Tennessee and Virginia. These entities own mineral rights, own or operate surface and underground mines and own interests in coal processing and loading facilities.

TECO Guatemala, Inc. (TECO Guatemala), a Florida corporation, owns consolidated subsidiaries that participate in two contracted Guatemalan power plants, San José and Alborada. In October 2010, TECO Guatemala sold its 30% interest in Distribución Eléctrica Centro Americana II, S.A. (DECA II), which had an ownership interest in Guatemala’s largest distribution utility, Empresa Eléctrica de Guatemala, S.A. (EEGSA) and other affiliated energy-related companies.


Revenues from Continuing Operations

 

(millions)

   2010     2009     2008  

Tampa Electric

   $ 2,163.2      $ 2,194.8      $ 2,091.2   

PGS

     529.9        470.8        688.4   
                        

Total regulated businesses

     2,693.1        2,665.6        2,779.6   

TECO Coal

     690.0        653.0        588.4   

TECO Guatemala (1)

     124.4        8.3        8.4   
                        
     3,507.5        3,326.9        3,376.4   

Other and eliminations

     (19.6     (16.4     (1.1
                        

Total revenues from continuing operations

   $ 3,487.9      $ 3,310.5      $ 3,375.3   
                        

 

(1) Revenues for the years ended Dec. 31, 2009 and 2008 are exclusive of entities deconsolidated as a result of accounting standards and include only revenues for the consolidated Guatemalan entities. Due to a change in these standards, these entities were reconsolidated as of Jan. 1, 2010.

For additional financial information regarding TECO Energy’s significant business segments including geographic areas, see Note 14 to the TECO Energy Consolidated Financial Statements. Also, see Note 19 for additional information regarding the deconsolidation and subsequent reconsolidation of the Guatemala subsidiaries.

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. Its Tampa Electric division is engaged in the generation, purchase, transmission, distribution and sale of electric energy. The retail territory served comprises an area of about 2,000 square miles in West Central Florida, including Hillsborough County and parts of Polk, Pasco and Pinellas Counties, with an estimated population of over one million. The principal communities served are Tampa, Winter Haven, Plant City and Dade City. In addition, Tampa Electric engages in wholesale sales to utilities and other resellers of electricity. It has three electric generating stations in or near Tampa, one electric generating station in southwestern Polk County, Florida and one electric generating station in long-term reserve standby located near Sebring, a city in Highlands County in South Central Florida.

Tampa Electric had 2,300 employees as of Dec. 31, 2010, of which 888 were represented by the International Brotherhood of Electrical Workers and 198 were represented by the Office and Professional Employees International Union.

In 2010, approximately 50% of Tampa Electric’s total operating revenue was derived from residential sales, 30% from commercial sales, 9% from industrial sales and 11% from other sales, including bulk power sales for resale. Approximately 5% of revenues are attributed to governmental municipalities. The sources of operating revenue and megawatt hour sales for the years indicated were as follows:

 

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Operating Revenue

 

(millions)

   2010     2009     2008  

Residential

   $ 1,100.0      $ 1,082.4      $ 981.7   

Commercial

     648.4        689.1        639.0   

Industrial – Phosphate

     84.2        81.2        66.1   

Industrial – Other

     103.7        111.0        111.2   

Other retail sales of electricity

     191.6        204.3        185.7   
                        

Total retail

     2,127.9        2,168.0        1,983.7   

Sales for resale

     41.6        42.4        69.7   

Other

     (6.3     (15.6     37.8   
                        

Total operating revenues

   $ 2,163.2      $ 2,194.8      $ 2,091.2   
                        

Megawatt-hour Sales

 

(millions)

   2010      2009      2008  

Residential

     9,185         8,667         8,546   

Commercial

     6,221         6,274         6,399   

Industrial

     2,010         1,995         2,205   

Other retail sales of electricity

     1,797         1,839         1,840   
                          

Total retail

     19,213         18,775         18,990   

Sales for resale

     516         440         884   
                          

Total energy sold

        19,729            19,215            19,874   
                          

No significant part of Tampa Electric’s business is dependent upon a single or limited number of customers where the loss of any one or more would have a significant adverse effect on Tampa Electric. Tampa Electric’s business is not highly seasonal, but winter peak loads are experienced due to electric space heating, fewer daylight hours and colder temperatures and summer peak loads are experienced due to the use of air conditioning and other cooling equipment.

Regulation

Tampa Electric’s retail operations 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 provides an opportunity for the utility to collect total revenues (revenue requirements) equal to its cost to provide service, plus a reasonable return on invested capital.

The costs of owning, operating and maintaining the utility systems, excluding fuel and conservation costs as well as purchased power and certain environmental costs for the electric system, are recovered through base rates. These costs include operation and maintenance expenses, depreciation and taxes, as well as a return on investment in assets used and useful in providing electric services (rate base). The rate of return on rate base, which is intended to approximate the individual company’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 (ROE). Base rates are determined in FPSC revenue requirement and rate setting hearings which occur at irregular intervals at the initiative of Tampa Electric, the FPSC or other parties.

Tampa Electric’s rates and allowed ROE range of 10.25% to 12.25%, with a midpoint of 11.25%, which was established in 2009, 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.

Before August 2008, Tampa Electric had not sought a base rate increase since 1992. As a result of lower customer and energy sales growth and significant annual capital investments, Tampa Electric’s 13-month average regulatory ROE was 8.7% at the end of 2008.

Recognizing the significant decline in ROE, Tampa Electric filed for a $228.2 million base rate increase in August

 

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2008. In March 2009, the FPSC approved a $104.3 million increase in annual base rates, authorizing a new ROE range of 10.25% to 12.25%, with a mid-point of 11.25% and an equity ratio of 54.0%, for rates effective in May 2009. The Commission also authorized a $33.5 million change in base rates effective Jan. 1, 2010 to recover the cost of five peaking combustion turbines and solid-fuel rail unloading facilities at the Big Bend Station, subject to the conditions that the investments were in commercial operation by Dec. 31, 2009 and the five peaking combustion turbines (CTs) are needed to serve customers. The FPSC later clarified that it would perform an audit to review the continuing need for the CTs and the costs incurred to place the CTs and rail unloading facilities in service.

In July 2009, in response to a motion for reconsideration, the FPSC determined that adjustments to the capital structure used to calculate the rates effective in 2009 should have been calculated over all sources of capital rather than only investor sources. This change resulted in a $9.3 million increase in revenue requirements in 2009 for a total increase of $113.6 million. At the same time, the FPSC voted to reject the intervenors’ joint motion requesting reconsideration of the 2010 portion of base rates approved in 2009.

In September 2009, the intervenors filed a joint appeal to the Florida Supreme Court related to the FPSC’s decision rejecting their motion for reconsideration of the 2010 portion of base rates approved in 2009.

In December 2009, the FPSC approved Tampa Electric’s petition requesting an effective date of Jan. 1, 2010 for the proposed rates supporting the CTs and rail unloading facilities and based on its Staff audit of Tampa Electric’s actual costs incurred, the Commission determined the portion of base rates approved in 2009 should be reduced by $8.3 million to $25.7 million, subject to refund. A regulatory proceeding was scheduled for October 2010 regarding the continuing need for the CTs, the appropriate amount to be recovered and the resulting rates.

In July 2010, Tampa Electric entered into a stipulation with the intervenors to resolve all issues related to the 2008 base rate case including the base rates effective Jan. 1, 2010 as well as the intervenors’ appeal to the Florida Supreme Court. Under the terms of the stipulation, the $25.7 million rate increase would remain in effect for 2010, Tampa Electric would make a one-time reduction of $24.0 million to customers’ bills in 2010 and effective Jan. 1, 2011, and for subsequent years, rates of $24.4 million (a $1.3 million reduction from the $25.7 million in effect for 2010) related to the rate increase will be in effect.

In August 2010, the FPSC approved the July stipulation, as filed in Docket No. 090368-EI “Review of the continuing need and cost associated with Tampa Electric Company’s 5 Combustion Turbines and Big Bend Rail Facility”. This stipulation resolved all issues in the above docket and all issues in the intervenors’ appeal of the FPSC’s 2009 decision in Tampa Electric’s base rate proceeding pending before the Florida Supreme Court. The docket related to the base rate proceeding is now closed. The one-time reduction of $24.0 million to customers’ bills in 2010 was reflected in operating results as a reduction in revenue and base rates reflect a total rate increase of $137.6 million as of Jan. 1, 2011.

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 fuel, environmental compliance, conservation programs and purchased power costs and estimated customer usage for a calendar year recovery period, with a true-up adjustment to reflect the variance of actual costs to projected costs for prior periods. The FPSC may disallow recovery of any costs it considers unreasonable or imprudently incurred.

In September 2010, Tampa Electric filed with the FPSC for approval of cost recovery rates for fuel and purchased power, capacity, environmental and conservation costs for the period January through December 2011. In November 2010, the FPSC approved Tampa Electric’s requested rates. The rates include the projected cost for natural gas, oil and coal, including transportation, for 2011 and the net over-recovery of fuel, purchased power and capacity clause expenses, which were collected in 2010 and 2009. Rates in 2010 also reflected a two-block residential fuel factor structure with a lower factor for the first 1,000 kilowatt-hours used each month for the first time. Due to increased reliance on natural gas to fuel its generating fleet and continued low natural gas prices, Tampa Electric’s residential customer rate per 1,000 kilowatt-hours decreased $5.22 from $112.73 in 2010 to $107.51 in 2011.

The FPSC determined it was appropriate for Tampa Electric to recover Selective Catalytic Reduction (SCR) operating costs through the Environmental Cost Recovery Clause (ECRC) as well as earn a return on its SCR investment installed on the Big Bend coal fired units for NOx control in compliance with the environmental consent decree. The SCR for Big Bend Unit 4 was reported in-service in May 2007, the SCR for Big Bend Unit 3 was reported in-service in June 2008, the SCR for Big Bend Unit 2 was reported in-service in May 2009 and the SCR for Big Bend Unit 1 was reported in-service in May 2010, and cost recovery started in the respective in-service years (see the Environmental Matters section).

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 and ancillary services, and accounting practices.

In July 2010, Tampa Electric filed wholesale requirements and transmission rate cases with the FERC. Tampa Electric’s last wholesale requirements rate case was in 1991 and the associated service agreements were approved by the

 

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FERC in the mid-1990s.

The transmission rate case updates Tampa Electric’s charges under its FERC-approved Open Access Transmission Tariff (OATT) for the various forms of wholesale transmission service it provides. These rates were last updated in 2003, pursuant to a settlement agreement between the company and its then transmission customers. The wholesale requirements rate proceeding addresses the rates and terms and conditions of Tampa Electric’s existing wholesale customers.

The FERC approved Tampa Electric’s proposed transmission rates as filed with the FERC, which became effective Sep. 14, 2010, subject to refund. The FERC also approved Tampa Electric’s proposed wholesale requirements rates, as filed with the FERC, to become effective Mar. 1, 2011, subject to refund. The proposed wholesale requirements and transmission rates are not expected to have a material impact on Tampa Electric’s results.

A procedural schedule including technical and settlement conference dates has been approved by the settlement judge in each case. Technical and settlement conferences have been held in both cases and the next settlement conference is scheduled for Mar. 15, 2011 in the requirements case.

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 the Environmental Matters section).

Transactions between Tampa Electric and its affiliates 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 retail and wholesale customers.

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 quality service to retail customers.

Presently, there is competition in Florida’s wholesale power markets, 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.

FPSC rules require Investor Owned Utilities (IOUs) to issue Request for Proposals (RFPs) prior to filing a petition for Determination of Need for construction of a power plant with a steam cycle greater than 75 megawatts. These rules provide a mechanism for expedited dispute resolution, allow bidders to submit new bids whenever the IOU revises its cost estimates for its self-build option, require IOUs to disclose the methodology and criteria to be used to evaluate the bids, and provide more stringent standards for the IOUs to recover cost overruns in the event the self-build option is deemed the most cost-effective.

Fuel

Approximately 58% of Tampa Electric’s generation of electricity for 2010 was coal-fired, with natural gas representing approximately 42% and oil representing less than 1%. Tampa Electric used its generating units to meet approximately 91% of the total system load requirements, with the remaining 9% coming from purchased power. The following table shows Tampa Electric’s average delivered fuel cost per million British thermal unit (Btu) and average delivered cost per ton of coal burned:

 

Average cost per million Btu

   2010      2009      2008      2007      2006  

Coal

   $ 3.12       $ 3.05       $ 2.91       $ 2.57       $ 2.49   

Oil

   $ 16.43       $ 16.01       $ 20.48       $ 13.87       $ 13.39   

Gas (Natural)

   $ 6.74       $ 8.00       $ 10.61       $ 9.52       $ 9.61   

Composite

   $ 4.49       $ 5.02       $ 5.56       $ 5.05       $ 4.75   
                                            

Average cost per ton of coal burned

   $ 75.87       $ 79.28       $ 69.14       $ 60.72       $ 58.75   
                                            

 

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Tampa Electric’s generating stations burn fuels as follows: Bayside, with units 3 through 6 entering commercial operation in 2009, burns natural gas; Big Bend Station, which has sulfur dioxide scrubber capabilities and nitrogen oxide reduction systems, burns a combination of high-sulfur coal and petroleum coke, No. 2 fuel oil and natural gas at CT4, which entered commercial operation in August 2009; Polk Power Station burns a blend of low-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, which burned residual fuel oil and was placed on long-term standby in September 2009.

Coal. Tampa Electric burned approximately 4.4 million tons of coal and petroleum coke during 2010 and estimates that its combined coal and petroleum coke consumption will be about 5.0 million tons for 2011. During 2010, Tampa Electric purchased approximately 75% of its coal under long-term contracts with four suppliers, and approximately 25% of its coal and petroleum coke in the spot market. Tampa Electric attempts to maintain a portfolio of 60% long-term versus 40% spot contracts, but market conditions, actual deliveries and unit performance can change this portfolio on a year-by-year basis. Tampa Electric expects to obtain approximately 67% of its coal and petroleum coke requirements in 2011 under long-term contracts with four suppliers and the remaining 33% in the spot market.

Tampa Electric’s long-term contracts provide for revisions in the base price to reflect changes in several important cost factors and for suspension or reduction of deliveries if environmental regulations should prevent Tampa Electric from burning the coal supplied, provided that a good faith effort has been made to continue burning such coal.

In 2010, approximately 77% of Tampa Electric’s coal supply was deep-mined, approximately 12% was surface-mined and the remaining was 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 cannot predict, however, the effect of any future mining laws and regulations.

Natural Gas. As of Dec. 31, 2010, approximately 46% of Tampa Electric’s 1,250,000 MMBtu gas storage capacity was full. Tampa Electric has contracted for 60% of the expected gas needs for the April 2011 through September 2011 period, 50% for October 2011 and 20% for November 2011 through March 2012. In early March 2011, Tampa Electric expects to issue an RFP and contract for additional gas to meet its generation requirements for these time periods. Additional volume requirements in excess of projected gas needs are purchased on the short-term spot market.

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

Franchises and Other Rights

Tampa Electric holds franchises and other rights that, together with its charter powers, govern the placement of Tampa Electric’s facilities on the public rights-of-way as it carries on its retail business in the localities it serves. The franchises specify the negotiated terms and conditions governing Tampa Electric’s use of public rights-of-way and other public property within the municipalities it serves during the term of the franchise agreement, and are irrevocable and not subject to amendment without the consent of Tampa Electric (except to the extent certain city ordinances relating to permitting and like matters are modified from time to time), although, in certain events, they are subject to forfeiture.

Florida municipalities are prohibited from granting any franchise for a term exceeding 30 years. The City of Temple Terrace reserved the right to purchase Tampa Electric’s property used in the exercise of its franchise if the franchise is not renewed. In the absence of such right to purchase, based on judicial precedent, if the franchise agreement is not renewed, Tampa Electric would be able to continue to use public rights-of-way within the municipality, 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 through September 2040.

Franchise fees payable by Tampa Electric, which totaled $38.6 million in 2010, are calculated using a formula based primarily on electric revenues and are collected on customers’ bills.

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

Environmental Matters

Among our companies, Tampa Electric has the most significant number of stationary sources with air emissions regulated by the Clean Air Act, material Clean Water Act implications, and potential implications due to possible federal and

 

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state legislative initiatives. Tampa Electric has undertaken major steps to dramatically reduce its air emissions through a series of voluntary actions, including technology selection (e.g., integrated gasification combined cycle (IGCC) and conversion of coal-fired units to natural-gas fired combined cycle); implementation of a responsible fuel mix taking into account price and reliability impacts to its customers; a substantial capital expenditure program to add Best Available Control Technology (BACT) emissions controls; implementation of additional controls to accomplish early reductions of certain emissions; and enhanced controls and monitoring systems for certain pollutants. Together, all of these improvements represent an investment in excess of $2 billion since 1994.

Through these actions, Tampa Electric has achieved significant reductions of all air pollutants, including CO2, while maintaining a reasonable fuel mix through the clean use of coal for the economic benefit of its customers.

Consent Decree

Tampa Electric, through voluntary negotiations with the U.S. Environmental Protection Agency (EPA), the U.S. Department of Justice (DOJ) and the Florida Department of Environmental Protection (FDEP), signed a Consent Decree, which became effective Feb. 29, 2000, and a Consent Final Judgment, which became effective Dec. 6, 1999, as settlement of federal and state litigation. Pursuant to these agreements, allegations of violations of New Source Review requirements of the Clean Air Act were resolved, a provision was made for environmental controls and pollution reductions, and Tampa Electric implemented a comprehensive program to dramatically decrease emissions from its power plants.

The emission reduction requirements included specific detail with respect to the availability of flue gas desulfurization systems (scrubbers) to help reduce SO2, projects for NOx reduction on Big Bend Units 1 through 4, and the repowering of the coal-fired Gannon Power Station to natural gas, which was renamed as the H. L. Culbreath Bayside Power Station (Bayside Power Station), in 2003 and 2004. Upon completion of the conversion, the station capacity was approximately 1,800 megawatts (nominal) of natural gas-fueled, combined-cycle electric generation. The repowering has reduced the facility’s NOx and SO2 emissions by approximately 99% and particulate matter (PM) emissions by approximately 92% from 1998 levels.

In 2004, Tampa Electric made its NOx reduction technology selection and decided to install SCR systems for NOx control on the four coal-fired Big Bend units. The units were reported in-service in May 2007, June 2008, May 2009 and May 2010.

The FPSC determined that it is appropriate for Tampa Electric to recover the operating costs of and earn a return on the investment in the SCRs installed on all four of the units at the Big Bend Power Station and pre-SCR projects on Big Bend Units 1–3 (which are early plant improvements to reduce NOx emissions prior to installing the SCRs) through the ECRC (see the Regulation section). Cost recovery for the SCRs began for each unit in the year that the unit entered service.

In November 2007, Tampa Electric entered into an agreement with the EPA and DOJ for a Second Amendment to the Consent Decree. The Second Amendment: 1) establishes a 0.12 lb/MMBtu NOx limit on a 30-day rolling average for Big Bend Units 1 through 3, which is lower than the original Consent Decree that had a provision for a limit as high as 0.15 lb/MMBtu depending on certain conditions; 2) allows for the sale of NOx allowances gained as a result of surpassing the emission limit goals of the Consent Decree; and 3) requires Tampa Electric to install a second Particulate Matter (PM) Continuous Emissions Monitoring System and potentially replace the originally installed system if the new system is successful.

Emission Reductions

Projects committed to under the Consent Decree and Consent Final Judgment have resulted in significant reductions in emissions. Since 1998, Tampa Electric has reduced annual SO2, NOx and PM emissions from its facilities by 164,000 tons, 63,000 tons, and 4,500 tons, respectively.

Reductions in SO2 emissions were accomplished through the installation of scrubber systems on Big Bend Units 1 and 2 in 1999. Big Bend Unit 4 was originally constructed with a scrubber. The Big Bend Unit 4 scrubber system was modified in 1994 to allow it to scrub emissions from Big Bend Unit 3 as well. Currently the scrubbers at the Big Bend Power Station are capable of removing more than 95% of the SO2 emissions from the flue gas streams.

The repowering of the Gannon Power Station to the Bayside Power Station has resulted in a significant reduction in emissions of all pollutant types. With the completion of the final Big Bend SCR in May 2010, the SCR projects resulted in a total phased reduction of NOx emissions by 63,000 tons per year from 1998 levels.

In total, Tampa Electric’s emission reduction initiatives have resulted in the annual reduction of SO2, NOx and PM emissions in 2010 by 94%, 91% and 87%, respectively, below 1998 levels. With these state-of-the-art improvements in place, Tampa Electric’s activities have helped to significantly enhance the quality of the air in the community. As a result of its

 

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completed emission reduction actions, Tampa Electric has achieved emission reduction levels called for in Phase I of the Clean Air Interstate Rule (CAIR). In July 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated CAIR on emissions of SO2 and NOx. The federal appeals court reinstated CAIR in December 2008 as an interim solution.

Tampa Electric has reduced mercury emissions through the repowering of the Gannon Power Station to the Bayside Power Station. At the Bayside Power Station, where mercury levels have decreased 99% below 1998 levels, there are virtually zero mercury emissions. Additional mercury reductions have been achieved from the installation of NOx controls at the Big Bend Power Station, which have led to a reduction of mercury emissions more than 75% from 1998 levels. The Clean Air Mercury Rule (CAMR) Phase I requirements were scheduled for implementation in 2010. The U.S. Court of Appeals for the District of Columbia Circuit vacated CAMR on Feb. 8, 2008. Prior to the court’s decision, Tampa Electric expected that it would have been in compliance with CAMR Phase I without additional capital investment.

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company, through its Tampa Electric and PGS divisions, is a potentially responsible party (PRP) for certain superfund sites and, through its PGS 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, 2010, Tampa Electric Company has estimated its ultimate financial liability to be approximately $21.3 million (primarily related to PGS), and this amount has been reflected in the company’s financial statements. This amount is higher than prior estimates to reflect a 2010 study for the costs of remediation primarily related to one site. 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 amounts represent only the estimated portion of the cleanup costs attributable to Tampa Electric Company. The estimates to perform the work are based on actual estimates obtained from contractors or Tampa Electric Company’s experience with similar work, adjusted for site specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

Allocation of the responsibility for remediation costs among Tampa Electric Company and other PRPs is based on each party’s 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 credit worthy.

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. Under current regulation, these additional costs would be eligible for recovery through customer rates.

In October 2010, the EPA notified Tampa Electric Company that it is a PRP under the federal Superfund law for the proposed contaminated soil removal action and further clean up, if necessary, at a property owned by Tampa Electric Company in Tampa, Florida. The property owned by Tampa Electric Company is undeveloped except for location of transmission lines and poles, and is adjacent to an industrial site, not owned by Tampa Electric Company, which the EPA has studied since 1992 or earlier. The EPA has asserted this potential liability due to Tampa Electric Company’s ownership of the property described above but, to the knowledge of Tampa Electric Company, is not based upon any release of hazardous substances by Tampa Electric Company. Tampa Electric Company is in the process of responding to such matter, and the scope of its potential liability, if any, and the costs of any required investigations and remediation have not been determined.

Capital Expenditures

Tampa Electric’s 2010 capital expenditures included $11.0 million for the installation of the final SCR equipment on the coal-fired Big Bend Unit 1 and $3.0 million for other environmental compliance projects. See the Liquidity, Capital Expenditures section of MD&A for information on estimated future capital expenditures related to environmental compliance.

PEOPLES GAS SYSTEM – Gas Operations

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.

Gas is delivered to the PGS system through three interstate pipelines. PGS does not engage in the exploration for or production of natural gas. PGS operates a natural gas distribution system that serves more than 336,000 customers. The system includes approximately 11,000 miles of mains and 6,500 miles of service lines. (See PGS’ Franchises and Other Rights section below.)

 

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PGS had 537 employees as of Dec. 31, 2010. A total of 79 employees in six of PGS’ 14 operating divisions are represented by various union organizations.

In 2010, the total throughput for PGS was almost 1.6 billion therms. Of this total throughput, 9% was gas purchased and resold to retail customers by PGS, 72% was third-party supplied gas that was delivered for retail transportation-only customers and 19% was gas sold off-system. Industrial and power generation customers consumed approximately 49% of PGS’ annual therm volume, commercial customers used approximately 26%, off-system sales customers consumed 19% and the balance was consumed by residential customers.

While the residential market represents only a small percentage of total therm volume, residential operations comprised about 30% of total revenues. Approximately 3% of revenues are attributed to governmental municipalities.

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. PGS has also seen increased interest and development in natural gas vehicles. Four new compressed natural gas stations have been connected in the past year with more planned for 2011.

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

 

     Revenues      Therms  

(millions)

   2010      2009      2008      2010      2009      2008  

Residential

   $ 159.5       $ 143.4       $ 150.5         90.5         73.5         74.4   

Commercial

     143.8         142.2         155.6         407.9         381.7         375.9   

Industrial

     171.2         125.8         325.7         507.2         448.7         513.3   

Power generation

     9.7         10.0         12.7         582.2         538.3         455.6   

Other revenues

     37.2         40.6         36.5         —           —           —     
                                                     

Total

   $ 521.4       $ 462.0       $ 681.0         1,587.8         1,442.2         1,419.2   
                                                     

No significant part of PGS’ business is dependent upon a single or limited number of customers where the loss of any one or more would have a significant adverse effect on PGS. PGS’ business is not highly seasonal, but winter peak throughputs are experienced due to colder temperatures.

Regulation

The operations of PGS are regulated by the FPSC separately from the regulation of Tampa Electric. 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 provides an opportunity for 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 ROE. Base rates are determined in FPSC revenue requirements 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–PGS Rates section of MD&A.

On May 5, 2009, the FPSC approved a base rate increase of $19.2 million that became effective on Jun. 18, 2009, and reflects a return on equity of 10.75%, which is the middle of a range between 9.75% and 11.75%. The allowed equity in capital structure is 54.7% from all investor sources of capital on an allowed rate base of $560.8 million.

As a result of the unprecedented cold winter weather in 2010, in the second quarter of 2010 PGS projected it would earn above the top of its ROE range of 11.75% in 2010. PGS recorded a $9.2 million total provision related to the 2010 earnings above the top of the range. In December 2010, PGS and the Office of Public Counsel entered into a stipulation and settlement agreement requesting Commission approval that $3.0 million of the provision to be refunded to customers in the form of a credit on customers’ bills in 2011, and the remainder be applied to accumulated depreciation reserves. On Jan. 25, 2011 the FPSC approved the stipulation.

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 delivers to its customers. These charges may be adjusted monthly based on a cap approved annually in an FPSC hearing. The cap is based on estimated costs of purchased gas and

 

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pipeline capacity, and estimated customer usage for a calendar year recovery period, with a true-up adjustment to reflect the variance of actual costs and usage from the projected charges for prior periods. In November 2010, the FPSC approved rates under PGS’ PGA clause for the period January 2011 through December 2011 for the recovery of the costs of natural gas purchased for its distribution customers.

In addition to its base rates and purchased gas adjustment clause charges, PGS customers (except interruptible customers) also pay a per-therm conservation charge for all gas. This charge is intended to permit PGS to recover costs incurred in developing and implementing energy conservation programs, which are mandated by Florida law and approved and supervised by the FPSC. PGS is permitted to recover, on a dollar-for-dollar basis, prudently incurred expenditures made in connection with these programs if it demonstrates the programs are cost effective for its ratepayers. The FPSC requires natural gas utilities to offer transportation-only service to all non-residential customers.

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

Although PGS is not in direct competition with any other regulated distributors of natural gas for customers within its service areas, there are other forms of competition. At the present time, the principal form of competition for residential and small commercial customers is from companies providing other sources of energy, including electricity, propane and fuel oil. 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. PGS has a “NaturalChoice” program, offering unbundled transportation service to customers consuming in excess of 1,999 therms annually, allowing these customers to purchase commodity gas from a third party but continue to pay PGS for the transportation. As a result, PGS receives its base rate for distribution regardless of whether a customer decides to opt for transportation-only service or continue bundled service. PGS had approximately 15,700 transportation-only customers as of Dec. 31, 2010 out of approximately 32,400 eligible customers.

Competition is most prevalent in the large commercial and industrial markets. In recent years, these classes of customers have been targeted by companies seeking to sell gas directly by transporting gas through other facilities and thereby bypassing PGS facilities. In response to this competition, PGS has developed various programs, including the provision of transportation-only services at discounted rates.

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 60 interconnections (gate stations) serving PGS’ operating divisions. In addition, PGS’ Jacksonville division receives gas delivered by the South Georgia Natural Gas Company pipeline through two gate stations located northwest of Jacksonville. Gulfstream Natural Gas Pipeline provides delivery through seven gate stations.

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 PGA 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

 

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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 and Other Rights

PGS holds franchise and other rights with approximately 100 municipalities throughout Florida. These franchises govern the placement of PGS’ facilities on the public rights-of-way as it carries on its retail business in the localities it serves. The franchises specify the negotiated terms and conditions governing PGS’ use of public rights-of-way and other public property within the municipalities it serves during the term of the franchise agreement. 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 2038. PGS expects to negotiate 14 franchises in 2011, the majority of which will be renewals of existing agreements. Franchise fees payable by PGS, which totaled $9.5 million in 2010, 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 that generally require monitoring, permitting and ongoing expenditures.

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

Capital Expenditures

During the year ended Dec. 31, 2010, PGS did not incur any material capital expenditures to meet environmental requirements, nor are any anticipated for the 2011 through 2015 period.

TECO COAL

TECO Coal, with offices located in Corbin, Kentucky, through its subsidiaries operates surface and underground mines as well as coal processing facilities in eastern Kentucky, Tennessee and southwestern Virginia.

TECO Coal owns no operating assets but holds all of the common stock of Gatliff Coal Company, Rich Mountain Coal Company, Clintwood Elkhorn Mining Company, Pike Letcher Land Company, Premier Elkhorn Coal Company, Perry County Coal Corporation and Bear Branch Coal Company. The TECO Coal subsidiaries (collectively referred to herein as TECO Coal) own or control, by lease, mineral rights, and own or operate surface and underground mines and coal processing and loading facilities. TECO Coal produces, processes and sells bituminous, predominately low sulfur coal of steam, industrial and metallurgical grades. TECO Coal uses two distinct extraction techniques: continuous underground mining and dozer and front-end loader surface mining.

TECO Coal currently operates 24 underground mines, which employ the room and pillar mining method, and 10 surface mines. In 2010, TECO Coal sold 8.77 million tons of coal. None of this coal was sold to Tampa Electric. For the

 

13


reporting period, TECO Coal had a combined estimated 267.6 million tons of proven and probable recoverable reserves. Historically, from time to time, TECO Coal has added to its proven and probable reserves. TECO Coal will continue to explore for additional reserves in and around its existing mining operations to prudently maintain or expand its reserves as appropriate.

History

In 1967, Cal-Glo Coal Company was formed. It mined a product containing low sulfur, low ash fusion characteristic and high energy content. Realizing the potential for this product to meet its combustion, quality and environmental requirements, Tampa Electric Company purchased Cal-Glo Coal Company in 1974. In 1982, after several years of continued growth and success, TECO Coal Corporation was formed and Cal-Glo Coal Company was renamed Gatliff Coal Company. Rich Mountain Coal Company was established in 1987, when leases were signed for properties in Campbell County, Tennessee.

In addition, in that year properties were also acquired in Pike County, Kentucky and Clintwood Elkhorn Mining Company was formed. Premier Elkhorn Coal Company and Pike Letcher Land Company were formed in 1991, when additional property was acquired in Pike and Letcher Counties, Kentucky.

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

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

In 2004, the acquisition of properties and the Millard Preparation Facilities (currently leased to a non-affiliated company) from American Electric Power and Kentucky Coal, LLC was completed. The property and facility are located in Pike County, Kentucky.

Mining Operations

TECO Coal currently has four mining complexes, all operating in Kentucky with a portion of Clintwood Elkhorn Mining Company operating in Virginia as well. A mining complex is defined as all mines that supply a single wash plant, except in the case of Clintwood Elkhorn Mining Company, which provides production for two active wash plants. Clintwood Elkhorn’s Millard Plant is currently leased to a non-affiliated company. These complexes blend, process and ship coal that is produced from one or more mines, with a single complex handling the coal production of as many as 12 individual underground or surface mines. TECO Coal uses two distinct extraction techniques: continuous underground mining; and dozer and front-end loader surface mining sometimes accompanied by highwall mining.

The complexes have been developed at strategic locations in close proximity to the TECO Coal preparation plants and rail shipping facilities. Coal is transported from TECO Coal’s mining complexes to customers by means of railroad cars, trucks, barges or vessels, with rail shipments representing approximately 93% of 2010 coal shipments. The following map shows the locations of the four mining complexes and TECO Coal’s offices in Corbin, Kentucky.

 

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LOGO

Facilities

Coal mined by the operating companies of TECO Coal is processed and shipped from facilities located at each of the operating companies, with Clintwood Elkhorn Mining Company having three facilities. The equipment at each facility is in good condition and regularly maintained by qualified personnel. Table 1 below is a summary of the TECO Coal processing facilities:

PROCESSING FACILITIES SUMMARY

Table 1

 

COMPANY

 

FACILITY

 

LOCATION

 

RAILROAD

SERVICE

 

UTILITY SERVICE

Gatliff Coal   Ada Tipple   Himyar, KY   CSXT 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
Clintwood Elkhorn   Millard Plant   Millard, KY   CSXT Railroad   American Electric Power
Premier Elkhorn   Burk Branch Plant   Myra, KY   CSXT Railroad   American Electric Power
Perry County Coal   Perry County Plant   Hazard, KY   CSXT Railroad   American Electric Power

Significant Projects

Significant projects for 2010 included the following:

 

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Clintwood Elkhorn Mining

 

   

Phase I engineering design and planning were completed on a clean coal recovery beltline which is to be installed at the Clintwood Elkhorn #3 Facilities. The project is expected to be completed in the third quarter of 2011. Clintwood Elkhorn also added an underground mine in the Elkhorn Three seam, in Island Creek in Pike County Kentucky.

Premier Elkhorn Coal

 

   

Premier Elkhorn began initial construction on three new deep mine portals. The face-ups should be completed and the mining operations are expected to begin in the second and third quarters of 2011. Premier Elkhorn also completed the portal construction and began production in a new Glamorgan seam mine.

Perry County Coal

 

   

Perry County Coal is finalizing the construction for the Second Creek Portals for E4-1 and E3-1 underground mines. When completed, TECO Coal expects to see a substantial reduction of travel time to the working mine face and more production. Completion is expected in the first quarter of 2011.

 

   

A major exploration program was conducted on the E4-2 mine area to further understand the quality and mineablity of the reserve basin. All geologic modeling was also finalized. This information will now be utilized for mine planning and market analysis for this large boundary of reserves.

 

   

Perry County Coal completed the acquisition of the First Creek reserves that are contiguous to the existing E4-1 mine.

Mining Complexes

Table 2 below shows annual production for each mining complex for each of the last three years.

MINING COMPLEXES

Table 2

 

                        

Tons Produced

(in millions)

    

Tons Sold

(in millions)

      
     Location   

Mine

Type

  

Mining

Equipment

   Transportation    2010      2009      2008      2010     

Year
Established

or Acquired

Gatliff Coal Company

  

Bell County, KY/ Knox

County, KY/ Campbell

County, TN

   S    D/L    T      0         0.2         0.3         0       1974

Clintwood Elkhorn Mining

  

Pike County, KY/

Buchanan County, VA

   U, S    CM, D/L,
HM, A
   R, R/V      2.1         2.0         2.6         2.3       1988

Premier Elkhorn Coal

  

Pike County, KY/Letcher

County, KY/ Floyd

County, KY

   U, S    CM, D/L    R,T,R/B,T/B      2.6         3.2         3.2         3.4       1991

Perry County Coal

  

Perry County, KY/

Leslie County, KY/

Knott County, KY

   U, S    CM, D/L,
HM
   R,T,R/B,T/B      3.1         3.1         3.1         3.1       2000
                                                  

TOTAL

                 7.8         8.5         9.2         8.8      

 

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S – Surface

U – Underground

CM – Continuous Miner

D/L – Dozers and Front-End Loaders

HM – Highwall Miner

A - Auger

R – Rail

R/B – Rail to Barge

R/V – Rail to Ocean Vessel

T – Truck

T/B – Truck to Barge

Gatliff Coal Company

Gatliff Coal Company discontinued surface mine operations in 2009. Poor market conditions and a depletion of the low sulfur content coal that was previously required on its sales contract led to the cessation of mining operations. Gatliff Coal Company had no coal production in 2010, leaving a reserve base of 3.4 million recoverable tons of predominantly low sulfur underground mineable coal which may later be recovered by Gatliff or by neighboring competing coal companies for coal royalty considerations. Rich Mountain Coal Company formerly operated as a contractor for Gatliff Coal Company’s Tennessee production, but is currently in non-producing reclamation status.

Clintwood Elkhorn Mining Company

Clintwood Elkhorn Mining Company has three facilities. One is located near Biggs, Kentucky in Pike County and is supplied by 11 underground mines and one surface mine. Principal products at the Biggs, Kentucky location include high volatile metallurgical coals and steam coal. The second Clintwood Elkhorn Mining Company facility is located near Hurley, Virginia and is supplied by three underground mines and two surface mines. The Hurley, Virginia operation facility also supplies high-volatile metallurgical coal as well as steam coal products. Products from both locations are shipped domestically to customers in North America via Norfolk Southern Corporation and vessels via the Great Lakes. International customers receive their products via ocean vessels from Lamberts Point, Virginia. The third facility, located at Millard, Kentucky, in Pike County is currently leased. In total, Clintwood Elkhorn Mining Company produced 2.1 million tons of coal in 2010, leaving a reserve base of 47.9 million recoverable tons.

Premier Elkhorn Coal Company

Located near Myra, in Pike County, Kentucky, Premier Elkhorn Coal Company is supplied by production from seven underground mines and five surface mines. Principal products include high-quality steam coal for utilities, specialty stoker products for ferro-silicon and industrial customers and PCI and metallurgical coal for the steel mills. Facilities include a unit train load-out with a 200 car siding capable of loading at 6,000 tons per hour as well as a single car siding. Products from this location are shipped via CSXT Railroad and trucking contractors to destinations in North America and internationally. All production is performed by Premier Elkhorn Coal Company even though Pike Letcher Land Company controls by fee and lease all of the recoverable reserves. Premier Elkhorn Coal Company produced 2.6 million tons of coal in 2010, leaving a reserve base of 70.2 million recoverable tons.

Perry County Coal Corporation

Located in Perry County Kentucky, near Hazard, Perry County Coal Corporation is supplied by three underground mines and two surface mines. Principal products include high quality steam coal for utilities, industrial stoker and PCI products. Facilities include an upgraded 1,350 ton per hour preparation plant and two unit train load-outs, each capable of loading at 5,000 tons per hour. Products from this location are shipped via CSXT Railroad and trucking contractors to destinations in both North America and internationally.

In 2009, Perry County Coal Corporation completed a comparable trade of underground reserves with another mining company of 16.0 million tons. During 2010, the boundary of reserves for the E4-2 mine area, was core drilled to confirm final reserve quantities and qualities and to finalize a comprehensive mining plan. A review of reserves for the E4-2 mine area for Perry County Coal Corporation proved an additional 6.9 million tons of reserves which were previously reported as resource coal. In 2010, Perry County Coal Corporation leased the First Creek reserve which is contiguous to its existing E4-1 underground mine. This new lease will facilitate the mining of approximately 10.0 million tons of high quality reserves. Perry

 

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County Coal Corporation produced 3.1 million tons of coal in 2010, leaving a total reserve base of 146.1 million recoverable tons.

Sales and Marketing

The TECO Coal marketing and sales force includes sales managers, distribution/transportation managers and administrative personnel. Primary customers are utility, steel and industrial companies. TECO Coal sells coal under long-term agreements, which are generally classified as greater than 12 months, and on a spot basis, which is generally classified as 12 months or less.

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

Distribution

TECO Coal transports coal from its mining complexes to customers by rail, barge, vessel and trucks. TECO Coal employs transportation specialists who coordinate the development of acceptable shipping schedules with its customers, transportation providers and mining facilities.

Competition

Primary competitors of TECO Coal are other coal suppliers, many of which are located in Central Appalachia. Even though consolidation and bankruptcy have decreased the number of coal suppliers, the industry is still intensely competitive. To date, TECO Coal has been able to compete for coal sales by mining high quality steam and specialty coals, including coals used for making coke and furnace injection, and by effectively managing production and processing costs.

Employees

As of Dec. 31, 2010, TECO Coal employed a total of 1,126 employees.

Regulations

Mine Safety and Health

The operations of underground mines, including all related surface facilities, are subject to the Federal Coal Mine Safety and Health Act of 1969, the 1977 Amendment and the Miner Act of 2006. 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, although mining accidents within the industry could lead to new legislation that could impose additional costs on TECO Coal.

Black Lung Legislation

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

In 2000, the Department of Labor issued amendments to the regulations implementing the federal black lung laws that, among other things, established a presumption in favor of a claimant’s treating physician, limited a coal operator’s

 

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ability to introduce medical evidence, and redefined Coal Workers Pneumoconiosis to include chronic obstructive pulmonary disease.

Under the Patient Protection and Affordable Care Act, signed into law in March 2010, miners with more than 15 years of experience and who have medical evidence of totally disabling lung disease are automatically granted black lung benefits rather than having to go through an application process proving they have black lung caused by being in the mines. Additionally, a surviving spouse is no longer required to reapply to receive the benefits. These changes in the regulations are expected to increase the number of claims, the percentage of claims approved and the overall cost of black lung to coal operators. TECO Coal, with the help of its consulting actuaries, continues to monitor claims very closely.

Workers’ Compensation

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

Environmental Laws

Surface Mining Control and Reclamation Act

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

Clean Air Act/Clean Water Act

While conducting their mining operations, TECO Coal’s subsidiaries are subject to various federal, state and local air and water pollution standards. In 2010, TECO Coal had expenditures of approximately $4.0 million for environmental protection and reclamation programs. TECO Coal expects to spend a similar amount in 2011 on these programs.

CERCLA (Superfund)

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

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

Glossary of Selected Mining Terms:

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

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

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

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

 

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

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

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

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

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

Deep mine. An underground coal mine.

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

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

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

High vol met coal. Coal that averages approximately 35% volatile matter. Volatile matter refers to a constituent that becomes gaseous when heated to certain temperatures.

Highwall miner. An auger-like apparatus that drives parallel rectangular entries to 1,000 feet into the coal seam.

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

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

Low ash fusion. Coal that when burned typically produces ash that has a melting point below 2,450 degrees Fahrenheit.

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

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

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

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

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

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

 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

 

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

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

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

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

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

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

TECO GUATEMALA

TECO Guatemala, Inc., has subsidiaries that have interests in independent power projects in Guatemala. The TECO Guatemala subsidiaries had 124 employees as of Dec. 31, 2010.

TECO Guatemala indirectly owns 100% of Central Generadora Eléctrica San José, Limitada (CGESJ), the owner of an electric generating station located in Guatemala, which consists of a single-unit pulverized-coal baseload facility (the San José Power Station). This facility was the first coal-fueled plant in Central America and meets environmental standards set by Guatemala and the World Bank. In 1996, CGESJ signed a U.S. dollar-denominated power purchase agreement (PPA) with EEGSA, the largest private distribution company in Central America, to provide 120 megawatts of capacity and energy for 15 years beginning in 2000. In 2001, CGESJ signed an option with EEGSA to extend that PPA for five years at the end of its current term for approximately $2.5 million. Tecnología Marítima, S.A. (TEMSA), an indirect wholly-owned subsidiary, in addition to receiving the coal shipments for CGESJ, provides unloading services to third parties.

Tampa Centro Americana de Electricidad, Limitada (TCAE), an entity 96.06% owned by TPS Guatemala One, Inc., a subsidiary of TECO Guatemala, and the owner of an oil-fired electric generating facility (the Alborada Power Station), has a U.S. dollar-denominated PPA with EEGSA to provide 78 megawatts of capacity ending in 2015. EEGSA is responsible for providing the fuel for the plant, with a subsidiary of TECO Guatemala providing assistance in fuel administration.

In 1998, DECA II, a consortium whose members included a subsidiary of TECO Guatemala, Iberdrola Energia, S.A. of Spain (Iberdrola), an electric utility in Spain, and Electricidade de Portugal, an electric utility in Portugal, completed the purchase of an 80.9% ownership interest in EEGSA for $520 million. In October 2010, TECO Guatemala sold its 30% interest in DECA II.

For CGESJ and TCAE, TECO Guatemala has obtained political risk insurance for currency inconvertibility, expropriation and political violence covering TECO Guatemala’s indirect equity investment and economic returns.

Our existing plants in Guatemala operate under environmental permits issued by the local environmental authorities. The plants were built in compliance with World Bank Guidelines of 1988 and 1994, at the time of construction of these facilities. TECO Guatemala complies with strict monitoring programs established by the local Ministry of Environment – MARN, which regulates local environmental laws and monitors compliance. TECO Guatemala has an environmental emission controls plan, monitoring programs as per the approved permits and lender requirements, pursuant to the referenced World Bank Guidelines.

TECO Guatemala operates its facilities under an approved environmental management plan, providing for efficient facility operation while promoting worker health and safety and reducing environmental impacts.

 

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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 The Last Five Years

Sherrill W. Hudson

   68   Executive Chairman of the Board, TECO Energy, Inc. and Tampa Electric Company, August 2010 to date; Chairman of the Board and Chief Executive Officer, TECO Energy, Inc. and Tampa Electric Company, July 2004 to August 2010.

John B. Ramil

   55   President and Chief Executive Officer, TECO Energy, Inc., and Chief Executive Officer, Tampa Electric Company, August 2010 to date; President and Chief Operating Officer, TECO Energy, Inc., July 2004 to August 2010.

Charles A. Attal, III

   51   Senior Vice President-General Counsel and Chief Legal Officer, TECO Energy, Inc., and General Counsel of Tampa Electric Company, February 2009 to date; Vice President-General Counsel and Chief Legal Officer, TECO Energy, Inc. and General Counsel of Tampa Electric Company, July 2007 to February 2009; and prior thereto, Vice President and Deputy General Counsel, TECO Energy, Inc.

Phil L. Barringer

   57   Vice President-Human Resources of TECO Energy, Inc. and Tampa Electric Company, July 2009 to date; President, TECO Guatemala, July 2009 to date; and prior thereto, Vice President-Controller, Operations of TECO Energy, Inc. and Chief Accounting Officer of Tampa Electric Company.

Deirdre A. Brown

   50   Vice President-Business Strategy and Compliance and Chief Ethics and Compliance Officer, TECO Energy, Inc., July 2009 to date; Vice President-Regulatory Affairs of Tampa Electric Company and Vice President-Customer Service, Tampa Electric Division of Tampa Electric Company, April 2006 to July 2009; Vice President-Regulatory Affairs, Tampa Electric Company, April 2005-April 2006.

Sandra W. Callahan

   58   Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer), TECO Energy, Inc., February 2011 to date and Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer), Tampa Electric Company, October 2009 to date; Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer), TECO Energy, Inc., October 2009 to February 2011; Vice President-Finance and Accounting and Chief Financial Officer (Treasurer and Chief Accounting Officer), TECO Energy, Inc. and Tampa Electric Company, July 2009 to October 2009; Vice President-Treasury and Risk Management (Treasurer and Chief Accounting Officer), TECO Energy, Inc., January 2007 to July 2009; Vice President-Treasury and Risk Management (Treasurer), TECO Energy, Inc., July 2000 to January 2007; Vice President-Treasurer and Assistant Secretary, Tampa Electric Company, April 2005 to July 2009.

Clinton E. Childress

   62   Senior Vice President-Corporate Services and Chief Human Resources Officer, TECO Energy, Inc., October 2004 to date; Chief Human Resources Officer and Procurement Officer, Tampa Electric Company, September 2003 to date.

Gordon L. Gillette

   51   President, Tampa Electric Company, July 2009 to date; Executive Vice President and Chief Financial Officer, TECO Energy, Inc., July 2004 to July

 

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     2009; President, TECO Guatemala, October 2004 to July 2009.
J. J. Shackleford    64   President of TECO Coal Corporation, since prior to 2006.

There is no family relationship between any of the persons named above or between executive officers and any director of the company. 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 May 4, 2011, and until such officer’s successor is elected and qualified.

 

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Item 1A. RISK FACTORS.

General Business and Operational Risks

General economic conditions may adversely affect our businesses.

Our businesses are affected by general economic conditions. In particular, growth in Tampa Electric’s service area and in Florida is important to the realization of annual energy sales growth for Tampa Electric and PGS. A failure of market conditions and the current Florida housing markets to improve could adversely affect Tampa Electric’s or PGS’ expected performance. Continuation or worsening of the current economic conditions could affect these companies’ ability to collect payments from customers.

TECO Coal and TECO Guatemala are also affected by general economic conditions in the industries and geographic areas they serve, both nationally and internationally.

Our electric and gas utilities are highly regulated; changes in regulation or the regulatory environment could reduce revenues or increase costs or competition.

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

Our financial results could be adversely affected if the FPSC were to lower the allowed ROE in the next base rate proceedings by Tampa Electric or PGS.

Tampa Electric and PGS were awarded ROE ranges with mid-points of 11.25% and 10.75% in their respective 2009 base rate proceedings. Recent decisions by the FPSC in investor owned utility rate cases awarded lower ROEs of 10.5% and 10%. If ROEs were reduced or other elements of the regulatory framework were changed, our financial results could be adversely affected.

Changes in the environmental laws and regulations affecting our businesses could increase our costs or curtail our activities.

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

Potential new regulations on the disposal and/or storage of coal combustion by-products (CCB) could add to Tampa Electric’s operating costs.

In 2009, in response to a coal ash pond failure at another utility, the EPA announced that it would propose new regulations regarding CCB handling, storage and disposal. The EPA has proposed two possible new rules related to CCB that could reduce or eliminate the beneficial use of coal combustion by-products, or eliminate the use of ponds for by-product storage. These proposed new rules could increase Tampa Electric’s operating costs through higher disposal costs. If the EPA eliminates the use of ponds for by-product storage, Tampa Electric would have to invest in dry handling and storage which could increase costs.

Federal or state regulation of Green House Gas (GHG) emissions, depending on how they are enacted, could increase our costs or the costs of our customers or curtail sales.

Among our companies, Tampa Electric has the most significant number of stationary sources with air emissions. While GHG emission regulations have been proposed, both at the federal and state level, none have been passed at this time and therefore, costs to reduce GHGs are unknown. Presently there is no viable technology to remove CO2 post-combustion from conventional coal-fired units such as Tampa Electric’s Big Bend units.

Regulation in Florida allows utility companies to recover from customers prudently incurred costs for compliance with new environmental regulations. Tampa Electric would expect to recover from customers the costs of power plant modifications or other costs required to comply with new GHG emission regulation. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, Tampa Electric

 

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could seek to recover those costs through a base-rate proceeding, but we cannot predict whether the FPSC would grant such recovery.

In the case of TECO Coal, the use of coal to generate electricity is considered a significant source of GHG emissions. New regulations, depending on final form, could cause the consumption of coal to decrease or the cost of sales to increase, which could negatively impact TECO Coal’s earnings.

The significant, phased reductions in GHG emissions called for by the Executive Orders signed by the former Governor of Florida in 2007 could add to Tampa Electric’s costs and adversely affect its operating results.

The former Governor of Florida signed three Executive Orders in July 2007 aimed at reducing Florida’s emissions of GHG. The three orders include directives for reducing GHG emissions by electric utilities to 2000 levels by 2017, to 1990 levels by 2025, and by 80 percent of 1990 levels by 2050.

Also in 2008, the state legislature passed broad energy and climate legislation. However, since that time, the process at the state level has slowed and is likely to be pushed out since the issue has become increasingly active at the federal level. It is unclear if the new Governor of Florida supports the reduction of GHG to the same degree as the former Governor.

However, if Florida does pass final GHG reduction rules that result in increased costs to Tampa Electric its operating results could be adversely affected.

A mandatory RPS could add to Tampa Electric’s costs and adversely affect its operating results.

In connection with the Executive Orders signed by the former Governor of Florida in July 2007, the FPSC was tasked with evaluating a RPS. The FPSC has made a recommendation to the Florida legislature that the RPS percentage be 7% by Jan. 1, 2013, 12% by Jan. 1, 2016, 18% by Jan. 1, 2019 and 20% by Jan. 1, 2021. The FPSC recommendation is subject to ratification by the Florida legislature, but to date the legislature has not adopted the FPSC’s recommendation. In addition, there is the potential that legislation could be proposed in the U.S. Congress to introduce an RPS at the federal level. It remains unclear, however, if or when action on such legislation would be completed. Tampa Electric could incur significant costs to comply with an RPS, as proposed. Tampa Electric’s operating results could be adversely affected if Tampa Electric were not permitted to recover these costs from customers.

Tampa Electric, the State of Florida and the nation as a whole are increasingly dependent on natural gas to generate electricity. There may not be adequate infrastructure to deliver adequate quantities of natural gas to meet the expected future demand and the expected higher demand for natural gas may lead to increasing costs for the commodity.

The deferral of Tampa Electric’s integrated gasification combined cycle (IGCC) unit and the cancellation of numerous proposed coal-fired generating stations in Florida and across the United States in response to GHG emissions concerns is expected to lead to an increasing reliance on natural gas-fired generation to meet the growing demand for electricity. Currently, there is an adequate supply and infrastructure to meet demand for natural gas in Florida and nationally. However, if in the future, supplies are inadequate or if significant new investment is required to install the pipelines necessary to transport the gas, the cost of natural gas could rise. Currently, Tampa Electric and PGS are allowed to pass the cost for the commodity gas and transportation services through to the customer without profit. Changes in regulations could reduce earnings for Tampa Electric and PGS if they required Tampa Electric and PGS to bear a portion of the increased cost. In addition, increased costs to customers could result in lower sales.

Our businesses are sensitive to variations in weather, the effects of extreme weather and have seasonal variations.

Our businesses are sensitive to variations in weather and the effects of extreme weather, and have seasonal variations. Climate change could lead to weather conditions other than what we routinely experience today.

Most of our businesses are affected by variations in general weather conditions and unusually severe weather, which are risks we already face. Tampa Electric’s and PGS’ energy sales are particularly sensitive to variations in weather conditions. Those companies forecast energy sales on the basis of normal weather, which represents a long-term historical average. If climate change, or other factors, cause significant variations from normal weather it could have a material impact on energy sales. Extreme weather conditions, such as hurricanes, can be destructive, causing outages and property damage that require the company to incur additional expenses. If warmer temperatures lead to changes in extreme weather events (increased frequency, duration and severity), these

 

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expenses could be greater. The speculative nature of such changes, however, and the long period of time over which any potential changes might be expected to take place, make estimating the physical risks difficult.

PGS, which has a typically short but significant winter peak period that is dependent on cold weather, is more weather-sensitive than Tampa Electric, which has both summer and winter peak periods. Mild winter weather in Florida can be expected to negatively impact results at PGS.

Variations in weather conditions also affect the demand and prices for the commodities sold by TECO Coal. Severe weather conditions could interrupt or slow coal production or rail transportation and increase operating costs.

The State of Florida is exposed to extreme weather, including hurricanes, which can cause damage to our facilities and affect our ability to serve customers.

As a company with electric service and natural gas operations in peninsular Florida, the company has substantial experience operating in areas prone to extreme weather events, such as hurricanes. The company has storm preparations and recovery plans in its operations that are routinely assessed and improved based upon experience during drills and events and planning with critical partners. Tampa Electric and PGS host meetings with state and local emergency management agencies to refine communications and restoration plans and consult with similarly situated utilities in preparing for restoration following extreme weather events. In addition to the design of its facilities and its storm recovery plans, the company continuously monitors and assesses the physical risks associated with severe weather conditions and adjusts its planning to reflect the results of that assessment.

While the company has storm preparation and recovery plans in place, and Tampa Electric and PGS have historically been granted regulatory approval to recover or defer the majority of significant storm costs incurred, extreme weather still poses risks to our operations and storm cost recovery petitions may not always be granted or may not be granted in a timely manner. If costs associated with future severe weather events cannot be recovered in a timely manner, or in an amount sufficient to cover actual costs, the financial condition and operating results could be adversely affected.

Commodity price changes may affect the operating costs and competitive positions of our businesses.

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

In the case of Tampa Electric, fuel costs used for generation are affected primarily by the cost of coal and natural gas. Tampa Electric is able to recover prudently incurred costs of fuel through retail customers’ bills, but increases in fuel costs affect electric prices, and therefore, the competitive position of electricity against other energy sources.

The ability to make sales and the margins earned on wholesale power sales are affected by the cost of fuel to Tampa Electric, particularly as it compares to the costs of other power producers.

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

In the case of TECO Coal, the selling price of coal affects the margins TECO Coal realizes on its sales, and may cause it to either decrease or increase production. If production is decreased, there may be costs associated with idling facilities or write-offs of reserves that are no longer economic.

In the case of TECO Guatemala, the dispatch price for some of the diesel generating resources in Guatemala, which use residual oil, have, at times, been above or below the average price of coal used by the San José Power Station due to prices for crude oil. Depending on the price of residual oil, generation from the San José Power Station for spot sales would rise or fall with oil prices, thus increasing or reducing non-fuel energy sales revenues and net income.

Changes in customer energy usage patterns, the impact of the Florida housing market, and the cost of complying with potential new environmental regulations, may affect sales at our utility companies.

Tampa Electric’s weather-normalized residential per customer usage declined in 2010, 2009 and 2008. We believe that mild weather patterns especially in the spring and fall, voluntary conservation in response to the

 

27


economic conditions, increased appliance efficiency, and increased residential vacancies as a result of higher foreclosures contributed to the declining per customer usage.

The utilities’ forecasts are based on normal weather patterns and historical trends in customer energy use patterns. Tampa Electric’s and PGS’ ability to increase energy sales and earnings could be negatively impacted if customers continue to use less energy in response to economic conditions or other factors.

Compliance with proposed GHG emissions reductions, a mandatory RPS or other new regulation could raise Tampa Electric’s cost. While current regulation allows Tampa Electric to recover the cost of new environmental regulation through the ECRC, increased costs for electricity may cause customers to change usage patterns, which would impact Tampa Electric’s sales.

We rely on some transmission and distribution assets that we do not own or control to deliver wholesale electricity, as well as natural gas. If transmission is disrupted, or if capacity is inadequate, our ability to sell and deliver electricity and natural gas may be hindered.

We depend on transmission and distribution facilities owned and operated by other utilities and energy companies to deliver the electricity and natural gas we sell to the wholesale and retail markets, as well as the natural gas we purchase for use in our electric generation facilities. If transmission is disrupted, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual and service obligations may be hindered.

The FERC has issued regulations that require wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, there is the potential that fair and equal access to transmission systems will not be available or that sufficient transmission capacity will not be available to transmit electric power as we desire. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities. Likewise, unexpected interruption in upstream natural gas supply or transmission could affect our ability to generate power or deliver natural gas to local distribution customers.

We may be unable to take advantage of our existing tax credits and deferred tax benefits.

We have generated significant tax credits and deferred tax assets that are being carried over to future periods to reduce future cash payments for income tax. Our ability to utilize the carry-over credits and deferred tax assets is dependent upon sufficient generation of future taxable income including foreign source income and capital gains. These tax credit carryforwards are subject to expiration periods of varying durations (see Note 4 to the TECO Energy Consolidated Financial Statements).

The current 2011-2012 federal budget, as proposed, includes the elimination of the percentage depletion tax deduction for coal mines and other hard mineral fossil fuels.

If the percentage depletion tax deduction is eliminated for TECO Coal, the effective tax rate for that company would rise from the expected 20% to 25% to the general corporate tax rate of 37%, which would have an adverse effect on TECO Coal’s financial results after 2011.

Impairment testing of certain long-lived assets and goodwill could result in impairment charges.

We test our long-lived assets and goodwill for impairment annually or more frequently if certain triggering events occur. Should the current carrying values of any of these assets not be recoverable, we would incur charges to write down the assets to fair market value.

Problems with operations could cause us to incur substantial costs.

Each of our subsidiaries is subject to various operational risks, including accidents, equipment failures, and operations below expected levels of performance or efficiency. As operators of power generation facilities, our subsidiaries could incur problems such as the breakdown or failure of power generation equipment, transmission lines, pipelines or other equipment or processes that would result in performance below assumed levels of output or efficiency. Our outlook assumes normal operations and normal maintenance periods for our operating companies’ facilities.

In January 2011, the EPA retracted a valid surface mining permit issued in 2007 to another coal mining company.

While the EPA has not taken this type of action on a routine basis, this action by the EPA creates additional

 

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uncertainty related to the ability to use surface mining techniques to mine coal, which could reduce the earnings expected from our coal company.

Failure to obtain the permits necessary to open new surface mines could reduce earnings from our coal company.

Our coal mining operations are dependent on permits from the U.S. Army Corp of Engineers (USACE) to open new surface mines necessary to maintain or increase production. For the past several years, new permits issued by the USACE under Section 404 of the Clean Water Act for new surface coal mining operations have been challenged in court by various environmental groups resulting in a backlog of permit applications and very few permits being issued. TECO Coal has four permits on the list of permits subject to enhanced review by the U.S. EPA under its memorandum of understanding with the USACE, which was issued in September 2009. To date, none of these permits have been issued. Failure to obtain the necessary permits to open new surface mines, which are required to maintain and expand production, could reduce production, cause higher mining costs or require purchasing coal at prices above our cost of production to fulfill contract requirements, which would reduce the earnings expected from our coal company.

In 2010, the EPA issued new guidelines related to water quality for Central Appalachian coal surface mining operations that would be conditions of new surface mine permits, which would add significant cost to operations or curtail our surface mining activities.

In 2010, the EPA issued new water quality standards for discharges from surface mining operations that would be conditions to the issuance of new permits, and may not be technically possible under most circumstances. Compliance with these conditions is projected to be very costly. The cost associated with compliance could make affected surface mining operations unprofitable or make the reserves no longer economic to develop.

Our international projects are subject to risks that could result in losses or increased costs.

Our projects in Guatemala involve numerous risks that are not present in domestic projects, including expropriation, political instability, currency exchange rate fluctuations, repatriation restrictions and regulatory and legal uncertainties. TECO Guatemala attempts to manage these risks through a variety of risk mitigation measures, including specific contractual provisions, obtaining non-recourse financing and obtaining political risk insurance where appropriate.

Guatemala, similar to many countries, has been experiencing higher electricity prices. As a result, TECO Guatemala’s operations are exposed to increased risks as the country’s government and regulatory authorities seek ways to reduce the cost of energy to its consumers.

Potential competitive changes may adversely affect our regulated electric and gas businesses.

The U.S. electric power industry has been undergoing restructuring. Competition in wholesale power sales has been introduced on a national level. Some states have mandated or encouraged competition at the retail level and, in some situations, required divestiture of generating assets. While there is active wholesale competition in Florida, the retail electric business has remained substantially free from direct competition. Although not expected in the foreseeable future, changes in the competitive environment occasioned by legislation, regulation, market conditions or initiatives of other electric power providers, particularly with respect to retail competition, could adversely affect Tampa Electric’s business and its expected performance.

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

We are a party from time to time to legal proceedings that may result in a material adverse effect on our financial condition.

From time to time, we are a party to, or otherwise involved in, lawsuits, claims, proceedings, investigations and other legal matters that have arisen in the ordinary course of conducting our business. While the outcome of these lawsuits, claims, proceedings, investigations and other legal matters which we are a party to, or otherwise involved in, cannot be predicted with certainty, any adverse outcome to lawsuits against us may result in a material adverse effect on our financial condition.

 

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Financing Risks

We have substantial indebtedness, which could adversely affect our financial condition and financial flexibility.

We have significant indebtedness, which has resulted in fixed charges we are obligated to pay. The level of our indebtedness and restrictive covenants contained in our debt obligations could limit our ability to obtain additional financing.

TECO Energy, TECO Finance and Tampa Electric Company must meet certain financial tests as defined in the applicable agreements to use their respective credit facilities. Also, TECO Energy, TECO Finance, Tampa Electric Company and other operating companies have certain restrictive covenants in specific agreements and debt instruments. The restrictive covenants of our subsidiaries could limit their ability to make distributions to us, which would further limit our liquidity. See the Credit Facilities section and Significant Financial Covenants table in the Liquidity, Capital Resources sections of Management’s Discussion & Analysis for descriptions of these tests and covenants.

As of Dec. 31, 2010, we were in compliance with required financial covenants, but we cannot be assured that we will be in compliance with these financial covenants in the future. Our failure to comply with any of these covenants or to meet our payment obligations could result in an event of default which, if not cured or waived, could result in the acceleration of other outstanding debt obligations. We may not have sufficient working capital or liquidity to satisfy our debt obligations in the event of an acceleration of all or a portion of our outstanding obligations.

We also incur obligations in connection with the operations of our subsidiaries and affiliates that do not appear on our balance sheet. These obligations take the form of guarantees, letters of credit and contractual commitments, as described under Liquidity, Capital Resources sections of the Management’s Discussion & Analysis.

Financial market conditions could limit our access to capital and increase our costs of borrowing or have other adverse effects on our results.

The financial market conditions that were experienced in 2008 and early 2009 impacted access to both the short-and long-term capital markets and the cost of such capital. In 2010 we were able to access the capital markets on favorable terms to refinance debt and extend maturities. Although we have no significant debt maturities in 2011 Tampa Electric has debt maturing in 2012 and TECO Finance has debt maturing in 2015, and both have credit facilities expiring in 2012. Future financial market conditions could limit our ability to raise the capital we need, or to renew our credit facilities, and could increase our interest costs which could reduce earnings.

We enter into derivative transactions with counterparties, most of which are financial institutions, to hedge our exposure to commodity price changes. Although we believe we have appropriate credit policies in place to manage the non-performance risk associated with these transactions, turmoil in the financial markets could lead to a sudden decline in credit quality among these counterparties. If such a decline occurs for a counterparty with which we have an in-the-money position, we could be unable to collect from such counterparty.

Despite the strong financial market recovery in 2010 and 2009, declines in the financial markets or in interest rates used to determine benefit obligations could increase our pension expense or the required cash contributions to maintain required levels of funding for our plan.

The value of our pension fund assets were negatively impacted by unfavorable market conditions in 2008. At Jan. 1, 2010 our plan was 90% funded under calculation requirements of the Pension Protection Act. However, as a result of the continued low interest rate environment, our funded percentage is expected to be approximately 80% as of the next Pension Protection Act measurement date of Jan. 1, 2011. This will require future contributions to the plan ranging from $35 - $50 million annually. Any future declines in the financial markets or a continued low-interest rate environment could increase the amount of contributions required to fund our plan in the future.

We estimate that pension expense in 2011 will be at levels consistent with 2010. Any future declines in the financial markets or a continuation of the low interest rate environment could cause pension expense to increase in future years.

Our financial condition and results could be adversely affected if our capital expenditures are greater than forecast.

We are forecasting capital expenditures at Tampa Electric to support the current levels of customer growth, to comply with the design changes mandated by the FPSC to harden transmission and distribution facilities against hurricane damage, to maintain transmission and distribution system reliability, and to maintain coal-fired generating

 

30


unit reliability and efficiency.

If we are unable to maintain capital expenditures at the forecasted levels, we may need to draw on credit facilities or access the capital markets on unfavorable terms. We cannot be sure that we will be able to obtain additional financing, in which case our financial position, earnings and credit ratings could be adversely affected.

Our financial condition and ability to access capital may be materially adversely affected by ratings downgrades, and we cannot be assured of any rating improvements in the future.

Our senior unsecured debt is rated as investment grade by Standard & Poor’s (S&P) at BBB- with a stable outlook, by Moody’s Investor’s Services (Moody’s) at Baa3 with a stable outlook, and by Fitch Ratings (Fitch) at BBB- with a positive outlook. The senior unsecured debt of Tampa Electric Company is rated by S&P at BBB with a stable outlook, by Moody’s at Baa1 with a stable outlook and by Fitch at BBB+ with a positive outlook. Any downgrades by the rating agencies may affect our ability to borrow, may change requirements for future collateral or margin postings, and may increase our financing costs, which may decrease our earnings. We also may experience greater interest expense than we may have otherwise if, in future periods, we replace maturing debt with new debt bearing higher interest rates due to any such downgrades. In addition, downgrades could adversely affect our relationships with customers and counterparties.

At current ratings, Tampa Electric and PGS are able to purchase electricity and gas without providing collateral. If the ratings of Tampa Electric Company decline to below investment grade, Tampa Electric and PGS could be required to post collateral to support their purchases of electricity and gas.

Because we are a holding company, we are dependent on cash flow from our subsidiaries, which may not be available in the amounts and at the times we need it.

We are a holding company and are dependent on cash flow from our subsidiaries to meet our cash requirements that are not satisfied from external funding sources. Some of our subsidiaries have indebtedness containing restrictive covenants which, if violated, would prevent them from making cash distributions to us. In particular, certain long-term debt at PGS prohibits payment of dividends to us if Tampa Electric Company’s consolidated shareholders’ equity is lower than $500 million. At Dec. 31, 2010, Tampa Electric Company’s consolidated shareholders’ equity was approximately $2.2 billion. Also, our wholly-owned subsidiary, TECO Diversified, Inc., the holding company for TECO Coal, has a guarantee related to a coal supply agreement that could limit the payment of dividends by TECO Diversified to us (see the TECO Energy Significant Financial Covenants table in the Liquidity, Capital Resources sections of Management’s Discussion & Analysis).

Various factors could affect our ability to sustain our dividend.

Our ability to pay a dividend, or sustain it at current levels, could be affected by such factors as the level of our earnings and therefore our dividend payout ratio, and pressures on our liquidity, including unplanned debt repayments, unexpected capital spending and shortfalls in operating cash flow. These are in addition to any restrictions on dividends from our subsidiaries to us discussed above.

Item 1B. UNRESOLVED STAFF COMMENTS.

None.

 

 

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Item 2. PROPERTIES.

TECO Energy believes that the physical properties of its operating companies are adequate to carry on their businesses as currently conducted. The properties of Tampa Electric are subject to a first mortgage bond indenture under which no bonds are currently outstanding.

TAMPA ELECTRIC

Tampa Electric has four electric generating plants in service, with a December 2010 net winter generating capability of 4,684 MW. Tampa Electric assets include the Big Bend Power Station (1,582 MW capacity from four coal units and 61 MW from a combustion turbine (CT)), the Bayside Power Station (2,083 MW capacity from two natural gas combined cycle units and four CTs), the Polk Power Station (220 MW capacity from the IGCC unit and 732 MW capacity from four CTs) and 6MW from the Howard Current Advanced Waste Water Treatment Plant, operated by the City of Tampa.

The Big Bend coal fired units went into service from 1970 to 1985 and the CT was installed in 2009. The Polk IGCC unit began commercial operation in 1996. In 1991, Tampa Electric purchased the Phillips Power Station from the Sebring Utilities Commission (Sebring) and it was placed on long-term reserve standby in 2009. Bayside Unit 1 was completed in April 2003, Unit 2 was completed in January 2004, Units 5 and 6 were completed in April 2009 and Units 3 and 4 were completed in July 2009.

Tampa Electric owns 180 substations having an aggregate transformer capacity of 22,368 Mega Volts Amps (MVA). The transmission system consists of approximately 1,322 pole miles (including underground and double-circuit) of high voltage transmission lines, and the distribution system consists of 6,329 pole miles of overhead lines and 4,669 trench miles of underground lines. As of Dec. 31, 2010, there were 672,280 meters in service. All of this property is located in Florida.

All plants and important fixed assets are held in fee except that titles to some of the properties are 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 or other property rights 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 Company has a long-term lease for the office building in downtown Tampa which serves as headquarters for TECO Energy, Tampa Electric, PGS and TECO Guatemala.

PEOPLES GAS SYSTEM

PGS’ distribution system extends throughout the areas it serves in Florida and consists of approximately 17,500 miles of pipe, including approximately 11,000 miles of mains and 6,500 miles of service lines. Mains and service lines are maintained under rights-of-way, franchises or permits.

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

TECO COAL

Property Control

TECO Coal operations are conducted on both owned and leased properties totaling over 265,000 acres in Kentucky, Tennessee and Virginia. TECO Coal’s current practice is to obtain a title review from a licensed attorney prior to purchasing or leasing property. As is typical in the coal mining industry, TECO Coal generally has not obtained title insurance in connection with its acquisitions of coal reserves and/or related surface properties. In many cases, the seller or lessor will grant the purchasing or leasing entity a warranty of property title. When leasing coal reserves and/or related surface properties where mining has previously occurred, TECO Coal may opt not to perform a separate title confirmation due to the previous mining activities on such a property. In cases involving less significant properties, and consistent with industry practices, title and boundaries are verified during lease or purchase negotiations.

In situations where property is controlled by a lease, the initial lease terms are expected to allow the reserves for the associated operation to be mined. The terms of many of these leases extend until the exhaustion of the mineable and merchantable coal from the leased property. If, however, extensions of the original lease term become necessary to exhaust

 

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the coal from the leased property, provisions are made within the original lease to allow extensions of the lease upon continued payment of minimum royalties.

Coal Reserves

As of Dec. 31, 2010, the TECO Coal operating companies had a combined estimated 267.6 million tons of proven and probable recoverable reserves. All of the reserves consist of High Vol A Bituminous Coal. Reserves are the portion of the proven and probable tonnage that meet TECO Coal’s economic criteria regarding mining height, preparation plant recovery, depth of overburden and stripping ratio. Generally, these reserves would be commercially mineable at year-end price and cost levels. Additionally, other controlled areas presently identified as resource now total 60.8 million tons of coal.

Reserves are defined by Security and Exchange Commission (SEC) Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows:

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

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

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

TECO Coal’s reserve estimates are prepared by its staff of geologists, with an average experience of 19 years. TECO Coal also has two chief geologists with the responsibility to track changes in reserve estimates, supervise TECO Coal’s other geologists and coordinate third party reviews of our reserve estimates by qualified mining consultants. In 2010, a third-party reserve audit was performed by Marshall Miller & Associates on the portion of reserves acquired during 2010. The results of that audit are reflected in the reserve included in this report.

Reserve Estimation Procedure

TECO Coal’s reserves are based on over 3,000 data points, including drill holes, prospect measurements and mine measurements. Our reserve estimates also include information obtained from our on-going exploration drilling and in-mine channel sampling programs. Reserve classification is determined by evaluation of engineering and geologic information along with economic analysis. These reserves are adjusted periodically to reflect fluctuations in the economics in the market and/or changes in engineering parameters and/or geologic conditions. Additionally, the information is constantly being updated to reflect new data for existing property as well as new acquisitions and depleted reserves.

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

During TECO Coal’s reserve evaluation and mine planning, TECO Coal takes into account factors such as restrictions under railroads, roads, buildings, power lines, or other structures. Depending on these factors, coal recovery may be limited or, in some instances, entirely prohibited. Current engineering practices are used to determine potential subsidence zones. The footprint of the relevant structure, as well as a safety angle-of-draw, is considered when mining near or under such facilities. Also, as part of TECO Coal’s reserve and mineability evaluation, TECO Coal reviews legal, economic and other technical factors. Final review and recoverable reserve determination is completed after a thorough analysis by TECO Coal engineers, geologists and financial management.

 

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The following table (Table 3) below shows recoverable reserves by quantity and the method of property control as well as the Assigned and Unassigned reserves per mining complex:

RECOVERABLE RESERVES BY QUANTITY (1)

(Millions of tons)

Table 3

 

                                             Assigned (2)      Unassigned(2)  
Mining Complex    Location    Total      Proven      Probable      Owned      Leased      2011      2010      2011      2010  

Gatliff Coal Company

   Bell County, KY/ Knox County, KY/ Campbell County, TN      3.4         3.0         0.4         1.2         2.2         0.5         0.5         2.9         2.9   

Clintwood Elkhorn Mining

  

Pike County, KY/

Buchanan County, VA

     47.9         39.9         8.0         3.2         44.7         47.9         50.0         —           —     

Premier Elkhorn Coal

   Pike County, KY/Letcher County, KY/ Floyd County, KY      70.2         52.8         17.4         38.9         31.3         61.8         64.4         8.4         8.4   

Perry County Coal

  

Perry County, KY/

Leslie County, KY/

Knott County, KY

     146.1         81.2         64.9         1.2         144.9         138.8         129.2         7.3         6.8   
                                                                                   
   Total      267.6         176.9         90.7         44.5         223.1         249.0         244.1         18.6         18.1   

Notes:

 

(1) Recoverable reserves represent the amount of proven and probable reserves that can actually be recovered from the reserve base taking into account all mining and preparation losses involved in producing a saleable product using existing methods under current law. Reserve information reflects a moisture of 6.5%. This moisture factor represents the average moisture present in TECO Coal’s delivered coal.
(2) Assigned reserves means coal which has been committed by the coal company to operating mine shafts, mining equipment, and plant facilities, and all coal which has been leased by the company to others. Unassigned reserves represent coal which has not been committed, and which would require new mineshafts, mining equipment, or plant facilities before operations could begin in the property.

The following table (Table 4) below shows the recoverable reserves by quality, including sulfur content and coal type, per mining complex:

RECOVERABLE RESERVES BY QUALITY (1)

(Millions of tons)

Table 4

 

            Sulfur Content                       
Mining Complex    Recoverable Reserves      < 1% (2)      >1% (2)      Compliance Tons (3)     

Average BTU/lb

As received

     Coal Type (4)  

Gatliff Coal Company

     3.4         3.2         0.2         —           13,500         LSU   

Clintwood Elkhorn Mining

     47.9         22.8         25.1         23.6         13,400         HVM, LSU, PCI   

Premier Elkhorn Coal

     70.2         40.0         30.2         24.3         13,350         IS, LSU, PCI, HVM   

Perry County Coal

     146.1         121.9         24.2         74.9         13,195         LSU, PCI, V   
                                         

Total

     267.6         187.9         79.7         122.8         

 

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Notes:

 

(1) Reserve information reflects a moisture factor of 6.5%. This moisture factor represents the average moisture present in TECO Coal’s delivered coal.
(2) <1% or >1% refers to sulfur content as a percentage in coal by weight.
(3) Compliance coal is any coal that emits less than 1.2 pounds of sulfur dioxide per million Btu when burned. Compliance coal meets sulfur emission standards imposed by Title IV of the Clean Air Act.
(4) Reserve holdings include metallurgical coal reserves. Although these metallurgical coal reserves receive the highest selling price in the current market when marketed to steel-making customers, they can also be marketed as an ultra-high Btu, low sulfur utility coal for electricity generation.

HVM – High Vol Met

LSU – Low Sulfur Utility

PCI – Pulverized Coal Injection

V – Various

IS – Industrial Stoker

TECO GUATEMALA

TPS San José International, Inc., a subsidiary of TECO Guatemala, has a 100% ownership in a project entity, CGESJ, which owns approximately 152 acres in Masagua, Guatemala on which the 120 MW coal-fired San José Power Station is located. TPS Guatemala One, Inc., a subsidiary of TECO Guatemala, has a 96.06% interest in TCAE, which owns approximately 11 acres in Escuintla, Guatemala on which the 78 MW oil-fired Alborada Power Station is located. TPS Operaciones, a subsidiary of TECO Guatemala which provides operations, maintenance and administrative support to CGESJ and TCAE, owns approximately 43 acres in Masagua, Guatemala.

Item 3. LEGAL PROCEEDINGS.

From time to time, TECO Energy and its subsidiaries are involved in various 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 accounting standards for contingencies to provide for matters that are probable of resulting in an estimable, material loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations or financial condition.

For a discussion of certain legal proceedings and environmental matters including an update of previously disclosed legal proceedings and environmental matters, see Notes 12 and 8, Commitments and Contingencies, of the TECO Energy, Inc. and Tampa Electric Company Consolidated Financial Statements, respectively.

Item 4. SPECIALIZED DISCLOSURES.

TECO Coal is subject to regulation by the federal Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977 (the Mine Act). Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) and the recently proposed Item 106 of Regulation S-K (17 CFR 229.106) is included in Exhibit 99.1 to this Annual Report.

 

35


PART II

 

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

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

 

     1st Quarter      2nd Quarter      3rd Quarter      4th Quarter  

2010

           

High

   $ 16.54       $ 17.35       $ 17.65       $ 18.11   

Low

   $ 14.46       $ 14.46       $ 14.78       $ 16.58   

Close

   $ 15.89       $ 15.07       $ 17.32       $ 17.80   

Dividend

   $ 0.20       $ 0.205       $ 0.205       $ 0.205   

2009

           

High

   $ 12.97       $ 12.41       $ 14.64       $ 16.71   

Low

   $ 8.41       $ 10.28       $ 11.16       $ 13.45   

Close

   $ 11.15       $ 11.93       $ 14.08       $ 16.22   

Dividend

   $ 0.20       $ 0.20       $ 0.20       $ 0.20   

The approximate number of shareholders of record of common stock of TECO Energy as of Feb. 21, 2011 was 13,746.

Dividends on TECO Energy’s common stock are declared and paid at the discretion of its Board of Directors. The primary sources of funds to pay dividends to its common shareholders are dividends and other distributions from its operating companies. TECO Energy’s $200 million credit facility contains a covenant that could limit the payment of dividends exceeding a calculated amount (initially $50 million) in any quarter under certain circumstances. This covenant is not applicable at TECO Energy’s current credit ratings. Certain long-term debt at PGS contains restrictions that limit the payment of dividends and distributions on the common stock of Tampa Electric Company.

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

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

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 on its common stock substantially equal to its net income. Such dividends totaled $239.3 million in 2010, $179.6 million in 2009 and $159.9 million in 2008. See the Restrictions on Dividend Payments and Transfer of Assets section in Note 1 to the Tampa Electric Company Consolidated Financial Statements for a description of restrictions on dividends on its common stock.

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

 

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     (a)
Total Number of
Shares  (or Units)
Purchased (1)
     (b)
Average Price
Paid per  Share

(or Unit)
     (c)
Total Number of
Shares  (or Units)
Purchased as Part
of Publicly
Announced Plans or
Programs
     (d)
Maximum Number
(or  Approximate
Dollar Value) of
Shares (or Units) that
May Yet Be
Purchased Under the
Plans or Programs
 

Oct. 1, 2010 – Oct. 31, 2010

     1,097       $ 17.59         —           —     

Nov. 1, 2010 – Nov. 30, 2010

     6,957       $ 16.91         —           —     

Dec. 1, 2010 – Dec. 31, 2010

     1,285       $ 17.03         —           —     
                                   

Total 4th Quarter 2010

     9,339       $ 17.01         —           —     
                                   

 

(1) These shares were not repurchased through a publicly announced plan or program, but rather relate to compensation or retirement plans of the company. Specifically, these shares represent shares delivered in satisfaction of the exercise price and/or tax withholding obligations by holders of stock options who exercised options (granted under TECO Energy’s incentive compensation plans), shares delivered or withheld (under the terms of grants under TECO Energy’s incentive compensation plans) to offset tax withholding obligations associated with the vesting of restricted shares and shares purchased by the TECO Energy Group Retirement Savings Plan pursuant to directions from plan participants or dividend reinvestment.

Shareholder Return Performance Graph

The following graph shows the cumulative total shareholder return on our common stock on a yearly basis over the five-year period ended Dec. 31, 2010, and compares this return with that of the S&P 500 Index and the S&P Multi Utility Index. The graph assumes that the value of the investment in our common stock and each index was $100 on Dec. 31, 2005 and that all dividends were reinvested.

 

37


LOGO

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

 

(millions, except per share amounts)

Years ended Dec. 31,

   2010      2009      2008      2007      2006  

Revenues

   $ 3,487.9       $ 3,310.5       $ 3,375.3       $ 3,536.1       $ 3,448.1   

Net income from continuing operations

   $ 239.6       $ 213.9       $ 162.4       $ 316.7       $ 174.8   

Net income from discontinued operations (1)

     —           —           —         $ 14.3       $ 1.9   

Net income attributable to TECO Energy(2)

   $ 239.0       $ 213.9       $ 162.4       $ 413.2       $ 246.3   
                                            

Total assets

   $ 7,173.9       $ 7,219.5       $ 7,147.4       $ 6,765.2       $ 7,361.8   

Long-term debt

   $ 3,226.4       $ 3,309.5       $ 3,213.5       $ 3,158.4       $ 3,212.6   

Earnings per share (EPS) – basic;

              

From continuing operations (1)

   $ 1.12       $ 1.00       $ 0.77       $ 1.90       $ 1.18   

From discontinued operations (1)

     —           —           —         $ 0.07       $ 0.01   
                                            

EPS basic

   $ 1.12       $ 1.00       $ 0.77       $ 1.97       $ 1.19   
                                            

Earnings per share (EPS) – diluted;

              

From continuing operations (1)

   $ 1.11       $ 1.00       $ 0.77       $ 1.89       $ 1.17   

From discontinued operations (1)

     —           —           —         $ 0.07       $ 0.01   
                                            

EPS diluted

   $ 1.11       $ 1.00       $ 0.77       $ 1.96       $ 1.18   
                                            

Dividends declared per common share

   $ 0.815       $ 0.800       $ 0.795       $ 0.775       $ 0.760   
                                            

 

(1) 2007 includes a $14.3 million gain on the 2005 sale of merchant power projects after reaching a favorable conclusion with taxing authorities.
(2) 2007 also includes a $221.3 million gain on the sale of TECO Transport.

 

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ITEM 7. MANAGEMENT’S DISCUSSION & ANALYSIS OF FINANCIAL CONDITIONS & RESULTS OF OPERATIONS

This Management’s Discussion & Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. Such statements are based on our current expectations, and we do not undertake to update or revise such forward-looking statements, except as may be required by law. These forward-looking statements include references to our anticipated capital expenditures, liquidity and financing requirements, projected operating results, future environmental matters, and regulatory and other plans. Important factors that could cause actual results to differ materially from those projected in these forward-looking statements are discussed under “Risk Factors.”

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

OVERVIEW

We are an energy-related holding company with regulated electric and gas utility operations in Florida, Tampa Electric and Peoples Gas System (PGS), respectively; TECO Coal, which owns and operates coal production facilities in the Central Appalachian coal production region; and TECO Guatemala, which is engaged in electric power generation and energy-related businesses in Guatemala.

Our regulated utility companies, Tampa Electric and PGS, operate in the Florida market. Tampa Electric serves more than 672,000 retail customers in a 2,000 square mile service area in West Central Florida and has electric generating plants with a winter peak generating capacity of 4,684 megawatts. PGS, Florida’s largest gas distribution utility, serves more than 336,000 residential, commercial, industrial and electric power generating customers in all of the major metropolitan areas of the state, with a total natural gas throughput of almost 1.6 billion therms in 2010.

We also have two unregulated companies. TECO Coal, through its subsidiaries, operates surface and underground mines and related coal processing facilities in eastern Kentucky and southwestern Virginia, producing metallurgical-grade and high-quality steam coals. Sales in 2010 were 8.8 million tons. TECO Guatemala, through its subsidiaries, owns a coal-fired generating facility and has a 96% ownership interest in an oil-fired peaking power generating plant, both under long-term contracts with a regulated distribution utility in Guatemala. In October 2010, TECO Guatemala sold its 24% ownership interest in Guatemala’s largest distribution utility, Empresa Eléctrica de Guatemala (EEGSA), and in affiliated companies (in combination called DECA II).

2010 PERFORMANCE

All amounts included in this Management’s Discussion & Analysis are after tax, unless otherwise noted.

In 2010, our net income and earnings per share attributable to TECO Energy were $239.0 million or $1.12 per share, compared to $213.9 million or $1.00 per share in 2009. Net income in 2010 included $33.5 million of charges related to early retirement of TECO Energy and TECO Finance debt, a net $3.9 million loss on the sale of DECA II, $0.9 million of the final restructuring charge for the 2009 restructuring described below and a $1.8 million benefit from the recovery of fees related to the previously sold McAdams Power Station.

Our non-GAAP results in 2010, which exclude the charges and gains discussed above, were $1.29 on a per share basis, compared to $1.08 in 2009 (see the 2010 and 2009 Reconciliation of GAAP net income from continuing operations to non-GAAP results tables). Our results in 2010 reflect the benefits of higher base rates approved by the FPSC for Tampa Electric effective in May 2009 and January 2010, and higher base rates for PGS approved by the FPSC effective in June 2009. PGS benefited from the coldest winter in 40 years in 2010, and Tampa Electric benefited from favorable weather throughout the year. TECO Coal realized higher margins, and TECO Guatemala benefited from substantially higher earnings from the San José Power Station, as the station operated normally throughout the year following the extended unplanned outages in 2009, and better results from DECA II prior to its sale in October 2010.

In 2009, our net income and earnings per share attributable to TECO Energy were $213.9 million or $1.00 per share, compared to $162.4 million or $0.77 per share in 2008. Net income in 2009 included $15.8 million of restructuring charges, a $5.2 million write-off of project development costs at Tampa Electric, primarily related to the Polk Unit 6 IGCC plant, a $3.8 million loss on student loan securities held at TECO Energy, and an $8.7 million net gain on the sale of TECO Guatemala’s 16.5% interest in the Central American fiber optic telecommunications provider, Navega.

Our non-GAAP results in 2009, which exclude the charges and gains discussed above, were $1.08 on a per share basis, compared to $0.87 in 2008 (see the 2009 and 2008 Reconciliation of GAAP net income from continuing operations to non-GAAP results tables). Our results in 2009 reflected the benefits of higher base rates at Tampa Electric and PGS effective in May and June 2009, respectively, and improved margins at TECO Coal as a result of higher selling prices. At

 

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TECO Guatemala, results reflected the impact of extended unplanned outages at the San José Power Station in the first half of 2009, the negative impact of lower Value Added Distribution (VAD) tariffs at EEGSA, the Guatemalan distribution utility, and lower net income from the unregulated affiliated companies due to the sale of Navega in the first quarter (see the TECO Guatemala section).

In 2010, we focused on managing our utility businesses to earn their allowed Returns on Equity (ROE) following the completion of their respective base rate cases in 2009. We used the proceeds from the sale of DECA II to retire parent debt, and we took advantage of improved financial market conditions to extend the maturities of certain TECO Finance and Tampa Electric Company debt at lower interest rates. In order to potentially take advantage of changing technology and evolving customer usage patterns, we initiated an evaluation of opportunities for our regulated utilities including, among other things, Smart Grid, alternative fueled vehicles and renewable energy sources. This ongoing evaluation is focused on developing longer range plans to take advantage of emerging growth and investment opportunities.

OUTLOOK

We remain focused on our long-term goal of investing in and growing our Florida utility businesses, while maximizing the returns from our other energy-related businesses, TECO Coal and TECO Guatemala. Reduction of parent debt also remains a priority and we expect continued progress at a modest pace, following the substantial debt retirement and debt restructuring achieved in 2010.

Our outlook for 2011 results reflects our expectation that our Florida utilities will continue to earn their authorized returns on equity, TECO Coal will benefit from improved margins due to strong contracted prices, TECO Guatemala will deliver lower earnings, and parent will benefit from substantially lower interest expense and tax impacts. The drivers impacting 2011 are summarized below and discussed in further detail in the individual operating company sections.

Tampa Electric expects customer growth in 2011 to continue at a pace similar to 2010 when the number of customers increased 0.6%. PGS expects customer growth less than Tampa Electric’s due to the more pronounced impact of the weak housing market in certain areas of Florida served by PGS, such as the Naples and Ft. Myers areas.

Energy sales at both utilities are likely to be lower in 2011 under an assumption of normal weather conditions. Record cold winter temperatures and, in the case of Tampa Electric, an early start to summer temperatures, boosted energy sales in 2010. At both utilities, however, the positive weather impact in 2010 was substantially offset by the impact of regulatory agreements that resulted in one-time reductions to net income in 2010.

We expect TECO Coal net income to increase in 2011 as higher contracted selling prices boost margins. With more than 90% of its expected 2011 sales contracted, the average contracted selling price across all products of $87 per ton is $11 per ton higher than 2010, while the fully-loaded, all-in cost of production is expected to be in a range between $74 and $78 per ton, or $5-9 per ton higher.

We expect lower results from TECO Guatemala in 2011, largely as a result of the October 2010 sale of its interest in DECA II, which had contributed about $13 million to net income in 2010 prior to its sale. TECO Guatemala expects normal operations and capacity payments and higher spot sales at its San José Power station, and a full year impact of the lower capacity rates that became effective for its Alborada Power Station when the power sales contract was extended in September 2010 at lower prices.

We expect the net costs of parent/other to decline substantially in 2011, reflecting lower interest expense and the absence of $10 million of tax charges that were specific to 2010. In addition to the retirement of $236 million of debt in December 2010, which will favorably impact 2011 results by $10 million, we expect to benefit from a full year of the first quarter 2010 refinancing and the retirement of the May 2011 maturity.

These forecasts are based on our current assumptions described in each operating company discussion, which are subject to risks and uncertainties (see the Risk Factors section).

Our priorities for the use of cash remain investment in the utility companies and reduction of parent debt. In 2011 we expect to make additional equity contributions to Tampa Electric and PGS to support their capital structures and financial integrity, and to retire $64 million of parent debt at maturity. We anticipate moderate capital spending in 2011 of $440 million. (See the Liquidity, Capital Resources section).

RESULTS SUMMARY

The table below compares our GAAP net income to our non-GAAP results. A reconciliation between GAAP net income and non-GAAP results is contained in the Reconciliation of GAAP net income from continuing operations to non-GAAP results tables for each year. A non-GAAP financial measure is a numerical measure that includes or excludes amounts, or is subject to adjustments that have the effect of including or excluding amounts that are excluded or included from the most directly comparable GAAP measure (see the Non-GAAP Information section).

 

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Results Comparisons

 

(millions)

   2010      2009      2008  

Net income attributable to TECO Energy

   $ 239.0       $ 213.9       $ 162.4   

Non-GAAP results

   $ 275.5       $ 230.0       $ 183.3   

In 2010, net income and earnings per share attributable to TECO Energy were $239.0 million, or $1.12 per share compared to $213.9 million, or $1.00 per share, in 2009. Our non-GAAP results which exclude charges and gains were $275.5 million, or $1.29 on a per share basis (see the 2010 and 2009 Reconciliation of GAAP net income from continuing operations to non-GAAP results tables). In 2009, net income and earnings per share attributable to TECO Energy were $213.9, or $1.00 per share, compared to $162.4 million, or $0.77 per share, in 2008. Our non-GAAP results in 2009, which exclude charges and gains, were $230.0 million, or $1.08 on a per share basis, compared to our 2008 non-GAAP results of $183.3 million, or $0.87 on a per share basis (see the 2009 and 2008 Reconciliation of GAAP net income from continuing operations to non-GAAP results tables).

Compared to 2009, our results in 2010 reflected higher earnings at both of the regulated utilities, Tampa Electric and PGS, and at TECO Coal and TECO Guatemala. In 2010 our net income and earnings per share were reduced by $36.5 million, or $0.17 per share, of net charges and gains, primarily related to early debt retirement costs, taxes on previously undistributed earnings at DECA II and the net loss on the sale of DECA II. Net income at Tampa Electric in 2010 reflected a one-time $24.0 million reduction in base revenues ($14.7 million after tax) associated with a regulatory agreement approved by the FPSC in August that resolved all outstanding issues in the 2008 base rate case (see the Tampa Electric section).

Compared to 2008, our results in 2009 reflected higher earnings at both of the regulated utilities, Tampa Electric and PGS, and at TECO Coal and lower earnings from TECO Guatemala. In 2009, our net income and earnings per share were reduced by a net $16.1 million, or $0.08 per share, of charges and gains, primarily related to restructuring actions and the write-off of project development costs at Tampa Electric. In 2008, our net income and earnings per share were reduced by a net $20.9 million of charges and gains consisting primarily of $21.6 million, or $0.10 per share, respectively, for income taxes related to the repatriation of cash and investments from TECO Guatemala, of which $9.6 million was recognized by TECO Guatemala and $12.0 million by TECO Energy parent, (see the 2008 Reconciliation of GAAP net income from continuing operations to non-GAAP results table).

2010 Earnings Summary

 

(millions) Except per-share amounts

   2010      2009      2008  

Consolidated revenues

   $ 3,487.9       $ 3,310.5       $ 3,375.3   
                          

Earnings per share – basic

        
                          

Earnings per share attributable to TECO Energy

   $ 1.12       $ 1.00       $ 0.77   
                          

Earnings per share – diluted

        
                          

Earnings per share attributable to TECO Energy

   $ 1.11       $ 1.00       $ 0.77   
                          

Net income attributable to TECO Energy

   $ 239.0       $ 213.9       $ 162.4   

Charges and (gains)(1)

     36.5         16.1         20.9   
                          

Non-GAAP results(2)

   $ 275.5       $ 230.0       $ 183.3   
                          

Average common shares outstanding

        

Basic

     212.6         211.8         210.6   
                          

Diluted

     214.8         213.1         211.4   
                          

 

(1) See the GAAP to non-GAAP reconciliation tables that follow.
(2) A non-GAAP financial measure is a numerical measure that includes or excludes amounts, or is subject to adjustments that have the effect of including or excluding amounts that are included or excluded from the most directly comparable GAAP measure (see the Non-GAAP Information section).

The following tables show the specific adjustments made to GAAP net income for each segment to develop our non-GAAP results:

 

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2010 Reconciliation of GAAP net income from continuing operations to non-GAAP results

 

Net income impact (millions)

   Tampa
Electric
     PGS      TECO
Coal
     TECO
Guatemala
    Parent/
Other
    Total  

GAAP Net income attributable to TECO Energy

   $ 208.8       $ 34.1       $ 53.0       $ 41.6      $ (98.5   $ 239.0   
                                                   

Restructuring charges

     —           —           —           —          0.9        0.9   

Taxes on previously undistributed earnings at DECA II

     —           —           —           24.9        —          24.9   

Gain on the sale of DECA II

     —           —           —           (27.0     6.0        (21.0

Charges related to early debt retirement

     —           —           —           —          33.5        33.5   

Recovery of fees related to McAdams Power Station sale

     —           —           —           —          (1.8     (1.8
                                                   

Total charges and (gains)

     —           —           —           (2.1     38.6        36.5   
                                                   

Non-GAAP results

   $ 208.8       $ 34.1       $ 53.0       $ 39.5      $ (59.9   $ 275.5   
                                                   

2009 Reconciliation of GAAP net income from continuing operations to non-GAAP results

 

Net income impact (millions)

   Tampa
Electric
     PGS      TECO
Coal
     TECO
Guatemala
    Parent/
Other
    Total  

GAAP Net income attributable to TECO Energy

   $ 160.2       $ 31.9       $ 37.2       $ 38.6      $ (54.0   $ 213.9   
                                                   

Restructuring charges

     11.3         2.9         —           —          1.6        15.8   

Project development cost write-off

     5.2         —           —           —          —          5.2   

Gain on the sale of Navega

     —           —           —           (8.7     —          (8.7

Charge related to student loan securities

     —           —           —           —          3.8        3.8   
                                                   

Total charges and (gains)

     16.5         2.9         —           (8.7     5.4        16.1   
                                                   

Non-GAAP results

   $ 176.7       $ 34.8       $ 37.2       $ 29.9      $ (48.6   $ 230.0   
                                                   

2008 Reconciliation of GAAP net income from continuing operations to non-GAAP results

 

Net income impact (millions)

   Tampa
Electric
     PGS      TECO
Coal
     TECO
Guatemala
     Parent/
Other
    Total  

GAAP Net income attributable to TECO Energy

   $ 135.6       $ 27.1       $ 18.0       $ 36.9       $ (55.2   $ 162.4   
                                                    

Waterborne transportation dispute settlement

     1.9         —           —           —           —          1.9   

Final adjustments associated with the sale of TECO Transport recorded at Parent

     —           —           —           —           (2.6     (2.6

Taxes on repatriation of cash and investments from Guatemala

     —           —           —           9.6         12.0        21.6   
                                                    

Total charges and (gains)

     1.9         —           —           9.6         9.4        20.9   
                                                    

Non-GAAP results

   $ 137.5       $ 27.1       $ 18.0       $ 46.5       $ (45.8   $ 183.3   
                                                    

NON-GAAP INFORMATION

From time to time, in this Management’s Discussion & Analysis of Financial Condition and Results of Operations, we provide non-GAAP results, which present financial results after elimination of the effects of certain identified gains and charges. We believe that the presentation of this non-GAAP financial performance provides investors a measure that reflects the company’s operations under our business strategy. We also believe that it is helpful to present a non-GAAP measure of performance that clearly reflects the ongoing operations of our business and allows investors to better understand and evaluate the business as it is expected to operate in future periods. Management and the Board of Directors use this non-GAAP presentation as a yardstick for measuring our performance, making decisions that are dependent upon the profitability of our various operating units and in determining levels of incentive compensation.

The non-GAAP measure of financial performance we use is not a measure of performance under accounting principles generally accepted in the United States and should not be considered an alternative to net income or other GAAP figures as an indicator of our financial performance or liquidity. Our non-GAAP presentation of results may not be comparable to similarly titled measures used by other companies.

While none of the particular excluded items is expected to recur, there may be adjustments to previously estimated gains or losses related to the disposition of assets or additional debt extinguishment activities. We recognize that there may be items that could be excluded in the future. Even though charges may occur, we believe the non-GAAP measure is important in addition to GAAP net income for assessing our potential future performance, because excluded items are

 

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limited to those that we believe are not indicative of future performance.

OPERATING RESULTS

This Management’s Discussion & Analysis of Financial Condition and Results of Operations utilizes TECO Energy’s consolidated financial statements, which have been prepared in accordance with GAAP, and separate non-GAAP measures to analyze the financial condition of the company. Our reported operating results are affected by a number of critical accounting estimates such as those involved in our accounting for regulated activities, asset impairment testing and others (see the Critical Accounting Policies and Estimates section).

The following table shows the segment revenues, net income and earnings per share contributions from continuing operations of our business segments on a GAAP basis (see Note 14 to the TECO Energy Consolidated Financial Statements).

 

(millions) Except per share amounts

         2010     2009     2008  

Segment revenues (1)

        

Regulated companies

     Tampa Electric      $ 2,163.2      $ 2,194.8      $ 2,091.2   
     Peoples Gas        529.9        470.8        688.4   
                          

Total regulated

     $ 2,693.1      $ 2,665.6      $ 2,779.6   
                          

Unregulated companies

     TECO Coal      $ 690.0      $ 653.0      $ 588.4   
     TECO Guatemala(2)        124.4        8.3        8.4   
                          

Total unregulated

     $ 814.4      $ 661.3      $ 596.8   
                          

Net income (3)

        

Regulated companies

     Tampa Electric      $ 208.8      $ 160.2      $ 135.6   
     Peoples Gas        34.1        31.9        27.1   
                          

Total regulated

       242.9        192.1        162.7   
                          

Unregulated companies

     TECO Coal        53.0        37.2        18.0   
     TECO Guatemala        41.6        38.6        36.9   
                          

Total unregulated

       94.6        75.8        54.9   
                          

Parent/other

       (98.5     (54.0     (55.2
                          

Net income attributable to TECO Energy

     $ 239.0      $ 213.9      $ 162.4   
                          

Earnings per share - basic (4)

        

Regulated companies

     Tampa Electric      $ 0.98      $ 0.76      $ 0.64   
     Peoples Gas        0.16        0.15        0.13   
                          

Total regulated

       1.14        0.91        0.77   
                          

Unregulated companies

     TECO Coal        0.25        0.17        0.08   
     TECO Guatemala        0.19        0.18        0.18   
                          

Total unregulated

       0.44        0.35        0.26   
                          

Parent/other

       (0.46     (0.26     (0.26
                          

Earnings attributable to TECO Energy

     $ 1.12      $ 1.00      $ 0.77   
                          

Average shares outstanding – basic

       212.6        211.8        210.6   
                          

 

(1) Segment revenues include intercompany transactions that are eliminated in the preparation of TECO Energy’s consolidated financial statements.
(2) Prior to 2010 Guatemalan entities CGESJ (San José) and TCAE (Alborada) were deconsolidated under accounting standards that were in effect at that time for variable interest entities.
(3) Segment net income and earnings are reported on a basis that includes internally allocated financing costs to the non-utility companies. Internally allocated finance costs were 6.5% for July through December 2010, 7.15% for September 2008 through June 2010 and 7.25% for January 2008 through August 2008.
(4) The number of shares used in the earnings-per-share calculations is basic shares.

TAMPA ELECTRIC

Electric Operations Results

Net income in 2010 was $208.8 million, compared to $160.2 million in 2009. There were no charges or gains in 2010. 2009 non-GAAP results were $176.7 million, which excluded the $11.3 million of restructuring charges and the $5.2 million write-off of project development costs primarily related to the Polk Unit 6 IGCC project. Net income and non-GAAP results in 2008 were $135.6 million and $137.5 million, respectively. Non-GAAP results in 2008 excluded the $1.9 million waterborne transportation settlement (see the 2009 and 2008 Reconciliation of GAAP net income from

 

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continuing operations to non-GAAP results table).

Results in 2010 were driven primarily by higher base revenues from favorable weather, new base rates, 0.6% higher average number of customers, higher earnings on NOx control projects, and higher operations and maintenance expenses. Net income in 2010 also reflected the one-time $24.0 million reduction in base revenues ($14.7 million after tax) associated with the regulatory agreement approved by the FPSC in August 2010, which resolved all outstanding issues in the 2008 base rate case. Net income included $1.9 million of AFUDC - equity, compared with $9.3 million in the 2009 period, which included AFUDC for NOx control projects, coal rail unloading facilities and peaking combustion turbines.

In 2010, total degree days in Tampa Electric’s service area were 14% above normal and 10% above 2009 levels. Pretax base revenue increased between $30 and $40 million from favorable weather in 2010. Pretax base revenues increased between $55 and $65 million in 2010 from new base rates approved by the FPSC for Tampa Electric effective in May 2009 and Jan. 1, 2010.

In 2010, total retail net energy for load, which is a calendar measurement of retail energy sales rather than a billing cycle measurement, increased 3.6%, compared to the 2009 period, driven primarily by favorable weather and the 0.6% increase in the average number of customers. Operations and maintenance expense excluding all FPSC-approved cost recovery clauses, increased $5.1 million, due to the accrual of performance-based incentive compensation for all employees partially offset by lower spending on generating unit maintenance.

Compared to 2009, depreciation and amortization expense increased $9.5 million, reflecting the additions to facilities to serve customers discussed above. In 2010, interest expense increased $4.0 million due to debt issued in 2009. Net income in 2010 reflected a $3.5 million tax benefit from the domestic production deduction compared to 2009, when no domestic production deduction was recorded.

Net income in 2009 was $160.2 million compared to $135.6 million in 2008. Tampa Electric’s full-year non-GAAP results were $176.7 million, which excluded $11.3 million of restructuring charges and the $5.2 million write-off of project development costs primarily related to the Polk Unit 6 IGCC plant, compared to non-GAAP results of $137.5 million in 2008, which excluded the $1.9 million waterborne transportation settlement (see the 2009 and 2008 Reconciliation of GAAP net income from continuing operations to non-GAAP results table).

Pretax base revenues increased approximately $72 million in 2009 from the higher base rates approved by the FPSC for Tampa Electric effective May 7, 2009. In the 2009 full-year period, there was no reduction in net income due to the waterborne transportation disallowance for the transportation of solid fuel, compared to an $8.9 million reduction in the 2008 period.

The higher 2009 base revenues were partially offset by lower retail energy sales and higher operations and maintenance, depreciation, property tax and interest expense. Results reflect 1.1% lower retail energy sales in 2009, primarily due to lower sales to commercial and industrial customers as a result of the weak Florida economy, and voluntary conservation by residential customers, which we believe was in response to the generally weaker economic conditions. Off-system sales declined due to lower state-wide demand. Total heating and cooling degree days were 4% above normal and 10% above 2008 levels. The average number of retail customers decreased 0.1% for the year.

In 2009, excluding all FPSC-approved cost recovery clause-related expenses, restructuring charges and the Polk 6 write-off, operations and maintenance expense increased $8.7 million, compared to 2008, primarily due to $2.1 million higher spending on generating unit maintenance and repairs, $1.7 million higher expenses to operate the distribution system, $3.0 million higher employee-related expenses, and $0.4 million higher bad debt expense. These increases were partially offset by savings in salaries and other benefits as a result of the restructuring actions taken in 2009. Depreciation and amortization expense increased $9.1 million reflecting additional facilities to serve customers. Interest expense increased due to higher long-term debt balances, and interest income decreased due to lower interest rates on lower under-recovered fuel balances. Net income also included $9.3 million of AFUDC-equity related to the construction of the peaking generation units, rail coal unloading facilities and the installation of NOx pollution control equipment, compared to $6.3 million in 2008.

Base Rates

Tampa Electric’s 13-month average regulatory ROE was 8.7% at the end of 2008 compared to an authorized midpoint of 11.75%, due to lower customer growth, slower energy sales growth, and ongoing high levels of capital investment. As a result, Tampa Electric filed for a $228 million base rate increase in August 2008. In March 2009, the FPSC awarded $104 million higher revenue requirements effective in May 2009 that authorized an ROE mid-point of 11.25%, 54.0% equity in the capital structure, and 2009 13-month average rate base of $3.4 billion. A component of that decision was a $34 million 2010 base rate step increase associated with the five peaking combustion turbines (CTs) and the solid-fuel rail unloading facilities at the Big Bend Power Station scheduled to enter service before the end of 2009.

In July 2009, in response to a motion for reconsideration, the FPSC determined that adjustments to the capital structure used to calculate the new rates should have been calculated over all sources of capital rather than only investor sources.

 

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This change resulted in $9.3 million higher revenue requirements in 2009. At the same time the FPSC voted to reject the intervenors’ joint motion requesting reconsideration of the 2010 portion of base rates approved in 2009.

In September 2009, the intervenors filed a joint appeal to the Florida Supreme Court related to the FPSC’s decision to reject their motion for reconsideration of the 2010 portion of base rates approved in 2009. The FPSC and Tampa Electric opposed this appeal.

In December 2009, the FPSC approved Tampa Electric’s petition requesting that the proposed rates to support the CTs and rail unloading facilities be put into effect Jan. 1, 2010. At that time, the FPSC determined that, based on its Staff audit of the actual costs incurred, the 2010 portion of the base rates approved in 2009 should be reduced by $8.4 million to $25.7 million, subject to refund. A regulatory proceeding was scheduled to be held in October 2010 regarding the continuing need for the CTs, the appropriate amount to be recovered and the resulting rates.

In July 2010, Tampa Electric entered into a stipulation with the intervenors to resolve all issues related to the 2008 base rate case including the 2010 step increase, as well as the intervenors’ appeal to the Florida Supreme Court. Under the terms of the stipulation, the $25.7 million step increase would remain in effect for 2010, and Tampa Electric would make a one-time reduction of $24.0 million to customers’ bills in 2010.

In August 2010, the FPSC voted to approve the July stipulation, which was contained in their Docket No. 090368-EI “Review of the continuing need and cost associated with Tampa Electric Company’s 5 Combustion Turbines and Big Bend Rail Facility”. This stipulation resolved all issues in the above docket and all issues in the intervenors’ appeal of the FPSC’s 2009 decision in Tampa Electric’s base rate proceeding pending before the Florida Supreme Court. The docket related to the base rate proceeding is now closed. The one-time reduction of $24.0 million to customers’ bills in 2010 is reflected in operating results as a reduction in revenue.

Effective Jan. 1, 2011, and for subsequent years, rates of $24.4 million (a $1.3 million reduction from the $25.7 million in effect for 2010) related to the step increase will be in effect.

Summary of Operating Results

 

(millions)

   2010      % Change     2009      % Change     2008  

Revenues

   $ 2,163.2         (1.4   $ 2,194.8         5.0      $ 2,091.2   
                                          

Other operating expenses

     289.5         18.3        244.7         17.8        207.7   

Maintenance

     116.1         (5.9     123.4         6.2        116.2   

Depreciation

     215.9         7.7        200.4         8.0        185.6   

Taxes, other than income

     145.3         0.3        144.9         6.2        136.5   
                                          

Restructuring costs

     —           —          18.4         —          —     
                                          

Non-fuel operating expenses

     766.8         4.8        731.8         13.3        646.0   
                                          

Fuel

     767.6         (16.9     923.3         12.7        819.4   

Purchased power

     179.6         1.1        177.6         (41.8     305.4   
                                          

Total fuel expense

     947.2         (14.0     1,100.9         (2.1     1,124.8   
                                          

Total operating expenses

     1,714.0         (6.5     1,832.7         3.5        1,770.8   
                                          

Operating income

     449.2         24.1        362.1         13.0        320.4   
                                          

AFUDC equity

     1.9         (79.6     9.3         47.6        6.3   
                                          

Net income

   $ 208.8         30.3      $ 160.2         18.1      $ 135.6   
                                          

Megawatt-Hour Sales (thousands)

            

Residential

     9,185         6.0        8,667         1.4        8,546   

Commercial

     6,221         (0.8     6,274         (2.0     6,399   

Industrial

     2,010         0.7        1,995         (9.5     2,205   

Other

     1,797         (2.3     1,839         —          1,840   
                                          

Total retail

     19,213         2.3        18,775         (1.1     18,990   

Sales for resale

     516         17.1        440         (50.2     884   
                                          

Total energy sold

     19,729         2.7        19,215         (3.3     19,874   
                                          

Retail customers-thousands (average)

     671.0         0.6        666.7         (0.1     667.3   
                                          

Operating Revenues

In 2010, retail megawatt hours, as measured on a billing cycle basis, increased 2.3% primarily due to favorable weather throughout the year and 0.6% customer growth. In 2010, total retail net energy for load, which is a calendar measurement of retail energy sales rather than a billing cycle measurement, increased 3.6%. Off-system sales (Sales for resale) increased 17.1%, primarily due to increased demand throughout Florida in response to cold winter weather.

In 2009 retail megawatt hour sales declined 1.1% primarily due to lower sales to commercial and industrial customers

 

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as a result of the weak Florida economy, and voluntary conservation by residential customers, which we believe was in response to the generally weaker economic conditions. Off-system sales declined due to lower state-wide demand. Total heating and cooling degree days were 4% above normal and 10% above 2008 levels. The average number of retail customers decreased 0.1% for the year. Pretax base revenues increased approximately $72 million in 2009 from the higher base rates approved by the FPSC, which were effective in May 2009.

For the past three years, weather-normalized energy consumption per residential customer declined due to the combined effects of voluntary conservation efforts, residential vacancies and changes in appliance efficiency. It is now apparent that some of the robust residential customer growth in the 2005 through mid-2007 period, which was measured by new meter installations, was actually vacant residences with minimal energy usage. The average number of residential customers with minimal usage was approximately 8% of total residential customers in 2010, 2009 and 2008.

Electricity sales to the phosphate industry increased 5.1% in 2010, following a 6.5% decrease in 2009. The 2010 increase in sales to phosphate customers was driven by higher operating rates at the customer’s facilities in response to higher demand for their products world wide. The 2009 decline in sales to phosphate customers was partially attributable to planned outages at their production facilities as the producers managed their product inventory levels during the economic downturn. Base revenues from phosphate sales represented about 3% of base revenues in 2010 and less than 3% in 2009. Sales to commercial customers decreased 0.8% in 2010 after a 2.0% decrease in 2009, reflecting the local economic conditions.

Energy sold to other utilities for resale increased 17.1% in 2010 due to increased demand throughout the State of Florida in response to cold winter weather early in the year. Energy sold to other utilities for resale decreased 50.2% in 2009 primarily due to lower energy demand state-wide and to lower natural gas prices through much of the summer, which made Tampa Electric’s base-load coal generation not the lowest cost form of energy for spot sales.

Customer and Energy Sales Growth Forecast

The Florida economy has started to recover from the economic downturn, but unemployment remains above the national level and the housing market, which was a major driver of growth in the Florida economy for many years, is not expected to improve until unemployment declines (see the Risk Factors section). In general, economists are forecasting a slow improvement in the unemployment rate in 2011, and a stronger improvement in the economy in 2012 and beyond. The forecast used by Tampa Electric reflects a continuation of the modest customer growth trend that was experienced in 2010 in 2011. Following the very strong energy sales in 2010 due to weather, absolute levels of energy sales are expected to decline assuming normal weather. On a weather-normalized basis energy sales are expected to decline slightly due to lower customer usage in response to increased energy efficiency, voluntary conservation and the continued economic weakness. The average number of customers increased 0.6% in 2010 following a 0.1% decline in 2009. Actual average 2008 customer growth was 0.1% reflecting customer growth early in the year that was partially offset by a decline in the number of customers late in the year.

Longer-term, assuming continued economic recovery and that growth from population increases and more robust business expansion resumes, Tampa Electric expects average annual customer growth to return to a level of nearly 1.5% and weather-normalized average retail energy sales growth at about that same level starting in the 2012 time frame. This energy sales growth projection is lower than in periods prior to the economic downturn, reflecting changes in usage patterns and changes in population trends. These growth projections assume continued modest local area economic growth, normal weather, a recovery in the housing market over time, and a continuation of the current energy market structure.

The economy in Tampa Electric’s service area grew modestly in 2010 after contracting in 2009 and 2008. The growth was lead primarily by the healthcare industry and tourism related businesses, but unemployment remains high. Initially, the contraction was centered in housing and related industries, but spread to the general economy later in 2007. The Tampa metropolitan area’s civilian employment increased 0.3% in 2010 after decreasing 5.1% in 2009 and 2.7% in 2008. This level of job creation is slightly higher than the 0.05% increase experienced in Florida. The local Tampa area unemployment rate decreased to 12.0% at year-end 2010, compared to 12.4% at year-end 2009, and 8.3% at the end of 2008. The Tampa area year-end 2010 unemployment rate was the same as the state of Florida, but higher than the 9.4% for the nation, which is contrary to the trends experienced in previous economic slowdowns.

Following the expiration of the home buyer tax credit in June 2010, as in most areas of the country, the housing market in Tampa Electric’s service area weakened for the remainder of 2010. As measured by the Case-Shiller Home Price Indices, home prices declined for much of the year and high numbers of foreclosures continued.

Operating Expenses

Total pretax operating expense decreased 6.5% in 2010 driven primarily by lower fuel expense. Excluding all FPSC-approved cost recovery clause-related expenses, the 2009 restructuring charges and the write-off of project development costs, operations and maintenance expense increased $5.1 million in 2010, due to the accrual of performance-based

 

46


incentive compensation for all employees partially offset by lower spending on generating unit maintenance and other savings as a result of the 2009 restructuring actions. Tampa Electric expects operation and maintenance expense, excluding fuel and purchased power, to decrease in 2011, assuming normal levels of employee incentive compensation accruals.

Total pretax operating expense increased 3.5% in 2009, driven by higher other operating expenses and maintenance expenses, which included the write-off of project development costs, the write-off of disallowed rate case expenses, and restructuring costs. Excluding all FPSC-approved cost recovery clause-related expenses, restructuring charges and the project development write-off, operations and maintenance expense increased $8.7 million, compared to 2008, primarily due to higher spending on generating unit maintenance and repairs, higher expenses to operate the distribution system, higher employee-related expenses, and slightly higher bad debt expense, partially offset by savings in salaries and other benefits as a result of the restructuring actions taken late in the year.

In 2010, depreciation and amortization expense increased $9.5 million, reflecting the additions to facilities to serve customers, which included peaking combustion turbines, NOx control projects and rail coal unloading facilities. In 2009, depreciation expense increased $9.1 million and taxes other than income, which include property taxes, were higher due to the peaking combustion turbines placed in service in 2009 and normal additions to facilities to serve customers. Depreciation expense is projected to increase in 2011, but at a level of about 50% of the 2010 increase due to routine plant additions to serve Tampa Electric’s customer base and maintain system reliability, but without the major incremental project completions as in 2009.

Fuel Prices and Fuel Cost Recovery

In November 2010, the FPSC approved cost recovery rates for fuel and purchased power, capacity, environmental and conservation costs for the period January through December 2011. The rates include the expected cost for natural gas and coal in 2011, and the net over-recovery of fuel, purchased power and capacity clause expenses, which were collected in 2010 and 2009 following the March mid-course adjustment described below.

In November 2009, the FPSC approved cost recovery rates for fuel and purchased power, capacity, environmental and conservation costs for the period January through December 2010. The rates included the expected cost for natural gas and coal in 2010, the net over-recovery of fuel, purchased power and capacity clause expenses, which were collected in 2009 following the March adjustment, and the operating cost for and a return on the capital invested in the fourth SCR project to enter service at the Big Bend Power Station as well as the operation and maintenance expense associated with the projects (see the Regulation and Environmental Compliance sections).

In November 2008, the FPSC approved Tampa Electric’s originally requested 2009 fuel rates. The rates included the costs for natural gas and coal expected in 2009, and the recovery of fuel and purchased power expenses, which were not collected in 2008. In March 2009, Tampa Electric filed a mid-course correction with the FPSC to adjust its projected 2009 fuel and purchased power costs to reflect the decline in commodity fuel prices, primarily natural gas. The revised forecast reduced fuel and purchased power costs by $191 million for 2009, which when combined with $35 million over recovery in late 2008, resulted in $226 million lower projected fuel and purchased power cost (see the Regulation section).

Total fuel cost decreased in 2010 due to significantly lower cost for natural gas partially offset by slightly higher cost for coal. Total fuel cost increased in 2009, due to higher cost for coal partially offset by lower cost for natural gas. Purchased power expense increased in 2010 due to higher volumes purchased, but at lower prices due to lower natural gas prices. Purchased power decreased in 2009 due to lower prices for natural gas, which is the primary fuel used by other generators in Florida. Delivered natural gas prices decreased 15.7% in 2010 due to abundant supplies from on-shore domestic natural gas produced from shale formations, and storage inventories above historic averages resulting from lower demand for natural gas from industrial users caused by economic conditions. Delivered coal costs increased 2.3% in 2010. Coal and natural gas prices were $3.12 per million Btu (/MMBtu) and $6.74/MMBtu, respectively, in 2010.

Natural gas futures as traded on the New York Mercantile Exchange (NYMEX) and various forecasts for natural gas prices indicate that natural gas prices will be stable for two to three years due to increased availability of on-shore domestic natural gas produced from shale formations. Coal prices, while less volatile, were relatively stable in 2010 after sharp increases in 2008 and 2007. Coal prices experienced a significant decline in 2009 for spot purchases, due to lower demand for coal fired generation of electricity as a result of the economic conditions. Tampa Electric’s primary coal supplies are from the Illinois Basin, which have experienced upward movements in prices over the past several years but not of the same magnitude as prices in the Central Appalachian coal producing region. Tampa Electric’s coal prices are expected to remain stable in 2011 due to longer-term supply contracts.

Energy Supply

On a retail energy supply basis, Tampa Electric generation accounted for 99%, 98% and 94% of the total retail energy sales in 2010, 2009 and 2008, respectively, with the remainder of the energy supplied by purchased power. Tampa Electric’s generation increased in 2010 due to the conclusion of the major coal-fired unit outages for the installation of

 

47


NOx control equipment. Purchased power expense increased 1.1%, but purchased power volumes increased 5.0%. The lower prices were driven by lower per-unit prices associated with the purchases as a result of lower natural gas prices. Purchased power expense is expected to decrease in 2011 due to a lower volume of purchases driven by normal generating unit outage schedules compared to a major SCR installation outage for the final unit in 2010.

Prior to 2003, nearly all of Tampa Electric’s generation was from coal. Starting in April 2003, the mix started to shift with increased use of natural gas at the Bayside Power Station, which was converted from the coal-fired Gannon Station. Nevertheless, coal is expected to continue to represent more than half of Tampa Electric’s fuel mix due to the baseload units at the Big Bend Power Station and the coal gasification unit, Polk Unit One. Natural gas prices are expected to remain stable in 2011 and we expect to maintain the generation mix at about 2010 levels.

Hurricane Storm Hardening

Due to extensive storm damage to utility facilities during the 2004 and 2005 hurricane seasons and the resulting outages utility customers experienced throughout the state, in 2006 the FPSC initiated proceedings to explore methods of designing and building transmission and distribution systems that would minimize long-term outages and restoration costs related to severe weather.

The FPSC subsequently issued an order requiring all investor owned utilities (IOUs) to implement a 10-point storm preparedness plan designed to improve the statewide electric infrastructure to better withstand severe storms and expedite recovery from future storms. Tampa Electric implemented its plan in 2007 and estimates the average non-fuel operation and maintenance expense of this plan to be approximately $20 million annually for the foreseeable future.

The FPSC also modified its rule regarding the design standards for new and replacement transmission and distribution line construction, including certain critical circuits in a utility’s system. Future capital expenditures required under the storm hardening program are expected to average more than $25 million annually for the foreseeable future (see the Regulation section).

Capital Spending

Prior to 2010, Tampa Electric was in a period of increased capital spending for infrastructure to reliably serve its customer base and for peaking generating capacity additions. In addition to the capital spending to comply with the storm hardening plan described above, Tampa Electric made capital investments in its transmission and distribution system to improve reliability and reduce customer outages, and for generating unit reliability.

Due to the recession experienced in the Florida and national economies and the Florida housing market slowdown in 2008 and 2009, Tampa Electric reassessed its forecast of long-term energy demand and sales growth. Tampa Electric had previously identified a need for new baseload capacity in early 2013; however, the current capital forecast reflects a deferral of construction of new baseload capacity beyond this forecast period. If growth resumes and demand increases above the current projections, Tampa Electric may require peaking capacity in the 2013 time frame. Tampa Electric may seek to purchase power rather than build additional capacity based on the economics of a decision to purchase rather than build new capacity (see the Capital Expenditures and Regulation sections).

Pending action by the Florida Legislature on a Florida Renewable Energy Portfolio Standard (RPS), the need for additional capital spending on renewable energy sources is likely but not yet defined (see the Environmental Compliance section). Depending on the final rules, which the legislature may enact in the 2011 legislative session, Tampa Electric may need to invest capital to develop additional sources of renewable power generation.

PEOPLES GAS (PGS)

Operating Results

PGS reported full year net income of $34.1 million in 2010, compared to net income of $31.9 million in 2009. There were no charges or gains in 2010. Non-GAAP results of $34.8 million in 2009 excluded $2.9 million of restructuring costs (see the 2009 Reconciliation of GAAP net income from continuing operations to non-GAAP results table). Results in 2009 included a $4.0 million favorable adjustment to previously recorded deferred tax balances. Results in 2010 reflect a 0.5% higher average number of customers. Residential customer usage increased due to the cold weather in the winter of 2010 and the coldest December on record. In 2010, pretax base revenues increased approximately $10 million due to the unprecedented cold winter weather and approximately $5 million due to the higher base rates, which became effective in June 2009. Increased sales to commercial and industrial customers reflect the colder-than-normal weather, the return to service of several higher volume customers that were idle in the 2009 period and generally higher usage by those customers. Gas transported for power generation customers and off system sales increased in 2010 due to higher power demand in the first quarter. Non-fuel operations and maintenance expense increased, primarily due to higher spending on pipeline integrity and pipeline awareness, partially offset by lower employee related costs as a result of the 2009 restructuring actions. Results in 2010 also reflect increased depreciation expense due to routine plant additions.

In 2010, the total throughput for PGS was almost 1.6 billion therms. Industrial and power generation customers

 

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consumed approximately 49% of PGS’ annual therm volume, commercial customers used approximately 26%, approximately 19% was sold off-system, and the balance was consumed by residential customers, which are essentially unchanged from 2009 sales.

Residential operations were about 30% of total revenues in 2010 and in 2009. New residential construction that includes natural gas and conversions of existing residences to gas has slowed significantly due to the weak Florida housing market. Like most other natural gas distribution utilities, PGS is adjusting to lower per-customer usage due to improving appliance efficiency. As customers replace existing gas appliances with newer, more efficient models, per-customer usage tends to decline.

As a result of the unprecedented cold winter weather in 2010, in the second quarter of 2010 PGS projected that it would earn above the top of its allowed ROE range of 9.75% to 11.75% in 2010. In 2010, PGS recorded a $9.2 million total pretax provision related to the earnings above the top of the range primarily in the second and third quarters. In December 2010, PGS and the Office of Public Counsel entered into a stipulation and settlement agreement that called for $3.0 million of the provision to be refunded to customers in the form of a credit on customer’s bills in 2011, and the remainder applied to deficiencies in accumulated depreciation reserves. On Jan. 25, 2011, the FPSC approved the stipulation.

PGS reported net income of $31.9 million in 2009, compared to $27.1 million in 2008. Non-GAAP results, which exclude $2.9 million of restructuring charges, were $34.8 million in 2009 (see the 2009 Reconciliation of GAAP net income from continuing operations to non-GAAP results table). There were no non-GAAP adjustments to the 2008 period. The higher 2009 results reflected a $4.0 million favorable adjustment to previously recorded deferred tax balances, and the new base rates effective in June 2009, partially offset by higher non-fuel operations and maintenance expenses and depreciation. Results reflected a 0.2% lower average number of customers. Residential customer usage increased due to colder winter weather in the first quarter of 2009, compared to the very mild winter weather in 2008. Sales to commercial customers increased, due to several higher volume new customers and conversion of propane customers to natural gas. Lower sales volumes to industrial customers reflected economic conditions and reduced operations by industries sensitive to the housing market, such as cement plants. Gas transported for power generation customers increased over 2008 due to lower natural gas prices, which made it a more economical generating fuel choice. Excluding restructuring charges, non-fuel operations and maintenance expense increased in 2009 compared to 2008 when operations and maintenance expense were reduced by a $1.5 million benefit from the recognition of environmental remediation insurance recoveries and a $0.9 million benefit related to the completion of pipeline installations for power generation customers. PGS experienced higher pipeline integrity costs and higher depreciation expense in 2009 due to routine plant additions.

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.

The actual cost of gas and upstream transportation purchased and resold to end-use customers is recovered through a Purchased Gas Adjustment (PGA). Because this charge may be adjusted monthly based on a cap approved by the FPSC annually, PGS normally has a lower percentage of under- or over-recovered gas cost variances than Tampa Electric.

Because of lower customer growth, slower energy sales growth, higher levels of operations and maintenance spending, continued investment in the distribution system and higher costs associated with required safety requirements, such as transmission and distribution pipeline integrity management, PGS’ 13-month average regulatory ROE was below the bottom of its allowed range at the end of 2007 and was 8.7% at the end of 2008.

Due to the significant decline in ROE, PGS filed for a $26.5 million base rate increase in August 2008. In May 2009, the FPSC awarded a $19.2 million revenue requirements increase that authorized an ROE mid-point of 10.75%, 54.7% equity in the capital structure, and a 2009 13-month average rate base of $561 million. The new rates were effective Jun. 18, 2009.

 

49


Summary of Operating Results

 

(millions)

   2010      % Change      2009      % Change     2008  

Revenues

   $ 529.9         12.6       $ 470.8         (31.6   $ 688.4   

Cost of gas sold

     284.8         16.5         244.5         (48.7     476.6   

Operating expenses

     171.8         5.2         163.3         8.6        150.3   
                                           

Operating income

     73.3         16.1         63.0         2.4        61.5   
                                           

Net income

     34.1         6.9         31.9         17.7        27.1   
                                           

Therms sold – by customer segment

             

Residential

     90.5         23.2         73.5         (1.2     74.4   

Commercial

     407.9         6.9         381.7         1.5        375.9   

Industrial

     507.2         13.0         448.7         (12.6     513.3   

Power generation

     582.2         8.1         538.3         18.1        455.6   
                                           

Total

     1,587.8         10.1         1,442.2         1.6        1,419.2   
                                           

Therms sold – by sales type

             

System supply

     451.0         13.3         398.0         (13.1     457.8   

Transportation

     1,136.8         8.9         1044.2         8.6        961.4   
                                           

Total

     1,587.8         10.1         1,442.2         1.6        1,419.2   
                                           

Customer (thousands) – average

     336.0         0.5         334.4         (0.2     335.1   
                                           

In Florida, natural gas service is unbundled for non-residential customers and residential customers that use more than 1,999 therms annually that elect this option, affording these customers the opportunity to purchase gas from any provider. The net result of unbundling is a shift from bundled transportation and commodity sales to transportation sales. Because the commodity portion of bundled sales is included in operating revenues at the cost of the gas on a pass-through basis, there is no net earnings impact to the company when a customer shifts to transportation-only sales. PGS markets its unbundled gas delivery services to customers through its “NaturalChoice” program. At year end 2010, approximately 15,700 out of 32,400 of PGS’ eligible non-residential customers had elected to take service under this program.

Since early 2008 at the start of the housing market collapse, customer growth and therm sales growth have been difficult to forecast, due to the state of the national and Florida economies and the uncertainty of the timing of a recovery in the Florida housing market. In 2010, PGS experienced 0.5% customer growth after forecasting no customer growth for the year. In 2009, PGS had a lower average number of customers than in 2008. In 2008, PGS had forecast customer growth of approximately 1.0%; however, actual customer growth was 0.2%, which was significantly lower than the average customer growth experienced for the previous five years. PGS provides service in areas of Florida that experienced some of the most rapid growth in 2005 and 2006, including the Miami, Ft. Myers and Naples areas. These areas continue to experience the most significant impacts of the housing market collapse.

PGS Outlook

In 2011, PGS expects continued modest customer growth, but at a rate lower than Tampa Electric due to the more severe housing market downturn in some of the areas it serves. Assuming normal weather, therm sales to weather sensitive customers, especially residential customers, are expected to be lower than in 2010 when exceptionally cold weather boosted therm sales. Excluding all FPSC-approved cost recovery clause-related expenses, operation and maintenance expense is expected to decrease in 2011 due to the absence of the $6.2 million provision to limit earnings to the top of the allowed ROE range that was recorded as an operating expense. Revenue was also reduced by $3.0 million in 2010 in accordance with this FPSC approved regulatory stipulation. Depreciation expense is expected to increase slightly from continued capital investments in facilities to reliably serve customers.

Since its acquisition by TECO Energy in 1997, PGS has expanded its gas distribution system into areas of Florida not previously served by natural gas, such as the lower southwest coast in the Ft. Myers and Naples areas and the northeast coast in the Jacksonville area. In 2011, PGS expects its capital spending to support modest system expansion in anticipation that the Florida housing market will recover over the next several years. Over time, PGS expects customer additions and related revenues to increase, assuming an economic and housing market recovery throughout the state of Florida and other factors (see the Risk Factors section).

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.

 

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Gas is delivered by the Florida Gas Transmission Company (FGT) through 60 interconnections (gate stations) serving PGS’ operating divisions. In addition, PGS’ Jacksonville Division receives gas delivered by the South Georgia Natural Gas Company pipeline through two gate stations located northwest of Jacksonville. PGS also receives gas delivered by Gulfstream Natural Gas Pipeline through seven gate stations.

PGS procures natural gas supplies using baseload 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.

TECO COAL

In 2010, TECO Coal recorded full year net income of $53.0 million on sales of 8.8 million tons in 2010, compared to $37.2 million on sales of 8.7 million tons in 2009. These results reflect an average net per-ton selling price, excluding transportation allowances, of more than $76 per ton, due to a sales mix that was more heavily weighted to metallurgical coal than in 2009 and higher prices for metallurgical coal. The all-in total per-ton cost of production increased to $69 per ton, from increased surface mine reclamation activities and generally higher mining costs due to productivity impacts associated with increased inspection activities. Full year net income includes a $5.3 million favorable net benefit from the settlement of state income tax issues recorded in prior years partially offset by a $1.1 million charge for other tax adjustments. TECO Coal’s 2010 effective income tax rate was 22%, excluding the income tax settlements discussed above, compared to 17% in the 2009 full year period.

TECO Coal recorded net income of $37.2 million in 2009, more than double the $18.0 million in 2008, on sales of 8.7 million tons, compared to sales of 9.3 million tons in 2008. Lower volume and the sales mix in 2009 reflected coal market conditions, which included high inventory levels at utility steam coal customers and reduced demand for coal used in the production of steel. At almost $72 per ton, the 2009 full-year average net per-ton selling price was 20% above the 2008 average selling price. At almost $67 per ton, the 2009 all-in total per-ton cost of production was 14% higher than in 2008. In 2009, TECO Coal’s effective income tax rate was 17%.

TECO Coal Outlook

We expect TECO Coal’s net income to increase in 2011 over 2010 from higher contract selling prices. TECO Coal has more than 90% of its expected 2011 sales of between 8.5 and 9.0 million tons contracted, resulting in an average contracted selling price across all products of $87 per ton. The product mix is expected to be about 40% specialty coal, which includes stoker, metallurgical and PCI coals, and the remainder utility steam coal. The cost of production is expected to increase to a range between $74 and $78 per ton due to expected higher contract miner costs, higher safety-related costs, higher royalties and severance costs, which are a function of selling price, and, due to delays in the issuance of permits, higher surface mining cost, primarily due to longer hauling distances. Diesel fuel prices have been hedged for those contracts that do not have diesel price adjustments in the contract at average prices at about the same level as 2010. TECO Coal’s effective income tax rate is expected to be the normal 25% for 2010.

At the end of 2011, an approximately 600,000 ton per year steam coal contract at below-market prices concludes.

Historically, from time to time, TECO Coal has added to its proven and probable reserves. TECO Coal will continue to explore for additional reserves in and around its existing mining operations to prudently maintain or expand its reserves as appropriate.

For the past several years, the issuance of permits by the U.S. Army Corp of Engineers (USACE) under Section 404 of the Clean Water Act required for surface mining activities in the Central and Northern Appalachian mining regions have been challenged in the courts. These challenges have been appealed by various mining companies affected on a number of occasions, but very few permits have been issued over the past several years. TECO Coal had six permits on the list of permits subject to enhanced review by the U.S. EPA under its memorandum of understanding with the USACE, which was issued in September 2009, however, two have been withdrawn. TECO Coal has all of the permits required to meet its 2011 sales projections. However, production from a mine affected by one of those permits that has been delayed is no longer included in the 2011 sales projection due to uncertainty in the ability to obtain a permit or the timing of the issuance of a permit. This mine was previously expected to contribute approximately 300,000 tons to 2011 sales. To date, there has been no progress in granting these permits. TECO Coal is currently producing from other mines, but at a higher cost, to offset the lost production from the delayed permit.

On Apr. 1, 2010, the EPA issued new guidance on environmental permitting requirements for Appalachian mountain top removal and other surface mining projects. The guidance limits conductivity (level of mineral salts) in water discharges into streams from permitted areas, and was effective immediately on an interim basis. The EPA will decide whether to modify the guidance after consideration of public comments and the results of the Science Advisory Board (SAB) technical review of the EPA scientific reports. Because the EPA’s standards appear to be unachievable under most circumstances, surface mining activity could be substantially curtailed since most new and pending permits would likely be rejected. This guidance could also be extended to discharges from deep mines and preparation plants, which could result in a substantial curtailing of those activities as well. This guidance is facing legal challenges from coal mining

 

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industry-related organizations and states relating to the stringency of the standards as well as the focus on the coal industry and the Appalachian region in particular.

Coal Markets

In the third quarter of 2008, in response to the U.S. economic recession, the prices for many commodities started to drop. The decline in commodity prices, including coal, accelerated in the fourth quarter of 2008 due to the spread of the U.S. economic recession to many other economies around the world. At that time, the U.S. steel industry, which is a large consumer of metallurgical coal, was reported to be operating at a less than 40% utilization rate. In the first half of 2009, coal producers around the world experienced generally depressed demand for their product, which resulted in lower shipments and lower prices. In the second half of 2009, government economic stimulus actions resulted in very strong demand for metallurgical coal in China and India. As the international economies started to emerge from the economic recession in late 2009, demand and prices for metallurgical coal increased, both in the U.S. and in international markets.

In 2010, prices for metallurgical coal remained strong driven by increased demand from expanding economies in China and India, and recovering demand in the U.S. and Europe. The U.S. steel industry operated at about a 70% utilization rate in 2010 compared to a 40% utilization rate for most of 2009. During 2010, spot price for various grades of metallurgical coal produced by TECO Coal and others reportedly ranged from $110 per ton to $180 per ton. TECO Coal was essentially fully contracted for its metallurgical coal sales by the start of 2010, with virtually no tons available for sale in the spot market.

Demand for coal used by utilities to generate electricity stabilized in 2010 as the economy started to recover and demand for electricity grew following a decline in 2009 due to the economic recession. Natural gas prices, as measured on a cent per million Btu basis, were below coal prices, which allowed utilities to substitute natural gas for coal in the generation of electricity. As a result, utility coal stockpiles were significantly above long-term averages entering 2010. In 2010, utility customers accepted delivery of contracted tons following deferrals of contracted tons into future years in 2009. A cold 2010 winter and a hot summer reduced utility inventories, but not enough to create near-term demand for utility steam coal.

Industry reports indicate that utilities are not expected to purchase significant amounts of coal for 2011 beyond what is already contracted for. Utilities that have indicated an interest in purchasing coal are purchasing tons for delivery after 2011. The industry expects demand for utility steam coal to recover in the second half of 2011 and at that time for prices to improve from the current spot prices of approximately $70 per ton.

The significant factors that could influence TECO Coal’s results in 2011 are the cost of production and the ability of the railroads to deliver the contracted volumes. Longer-term factors that could influence results include inventories at steam coal users, weather, the ability to obtain environmental permits for mining operations, general economic conditions, the level of oil and natural gas prices, commodity price changes that impact the cost of production, and changes in environmental regulations (see the Environmental Compliance and Risk Factors sections).

TECO GUATEMALA

Our TECO Guatemala operations include two power plants operating in Guatemala under long-term contracts. The San José and Alborada power stations in Guatemala both have long-term power sales contracts with the Guatemalan distribution utility EEGSA, the largest Guatemalan distribution utility, which serves Guatemala City, the capital of Guatemala and the surrounding region.

On Oct. 21, 2010, a TECO Guatemala subsidiary sold its 30% interest in DECA II to EPM, a multi-utility company based in Medellín Colombia, for a sale price of $181.5 million.

DECA II was a holding company in which, prior to the sale, TECO Guatemala Holdings, LLC (TGH), a wholly owned subsidiary of TECO Guatemala, held a 30% interest, Iberdrola Energia, S.A. (Iberdrola) held a 49% interest and Energias de Portugal, S.A. (EDP) held a 21% interest. Each of these parties sold its interest in DECA II. DECA II held an 80.9% ownership interest in EEGSA and affiliated companies.

TGH received $181.5 million of the $605.0 million total purchase price for its 30% interest. In addition, TGH repatriated approximately $25.0 million of cash previously held offshore in a tax deferral structure. TECO Guatemala recorded a $27.0 million gain on the sale, but the sale transaction resulted in a total net gain of $21.0 million for TECO Energy due to the $6.0 million negative valuation allowance recorded against foreign tax credits at TECO Energy Parent (see the 2010 and 2009 Reconciliation of GAAP net income from continuing operations to non-GAAP results tables). TECO Guatemala also recorded a $24.9 million income tax charge related to the unwinding of the tax deferral structure, as the earnings from DECA II were no longer considered indefinitely reinvested.

The Alborada Power Station, which consists of oil-fired, simple-cycle combustion turbines, is a peak-load facility with high availability, but operates at a low capacity factor by design. Guatemala is heavily dependent on hydro-electric

 

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sources for baseload power generation. The Alborada Power Station is under contract to EEGSA, but it is designated to be an operating reserve for the country of Guatemala by the country’s power dispatcher. The plant runs at peak times or in times of loss of a major generating unit or transmission circuit in the country. In 2001, TECO Guatemala exercised an option to extend the Alborada power sales contract for five years at the end of the contract period, which was originally scheduled for September 2010. The contract was extended for five years effective Sep. 14, 2010 at rates approximately 55%, or $7 million after tax on an annual basis, below the previous contract.

On Jan. 13, 2009, TGH delivered a Notice of Intent to the Guatemalan government that it intended to file an arbitration claim against the Republic of Guatemala under the Dominican Republic Central America – United States Free Trade Agreement (DR – CAFTA) alleging a violation of fair and equitable treatment of its investment in EEGSA. On Oct. 20, 2010, TGH filed a Notice of Arbitration with the International Centre for Settlement of Investment Disputes to proceed with its arbitration claim.

The arbitration was prompted by actions of the Guatemalan government in July 2008 which, among other things, unilaterally reset the distribution tariff for EEGSA at levels well below the tariffs in effect at the time that the distribution tariff was reset. These actions caused a significant reduction in earnings from EEGSA. As discussed above, until Oct. 21, 2010, TGH held a 24% ownership interest in EEGSA through a holding company DECA II when TGH’s interest was sold. In connection with the sale of TGH’s ownership interest in EEGSA, TGH reserved the right to pursue the arbitration claim described above. Iberdrola is in international arbitration under the bilateral trade treaty in place between the Republic of Guatemala and the Kingdom of Spain.

In 2010, TECO Guatemala reported net income of $41.6 million, compared to $38.6 million in 2009. In 2010, non-GAAP results were $39.5 million, which excluded a $27.0 million gain on the sale of its ownership interest in DECA II, and a $24.9 million tax charge related to previously undistributed earnings as a result of the sale. Non-GAAP results in 2009 were $29.9 million, which excluded an $8.7 million net gain on the sale of its minority ownership interest in the telecommunications company, Navega.

These results reflect the absence of earnings from DECA II for most of the fourth quarter, a $2.0 million reduction, lower capacity payments at the Alborada Power Station under the contract extension effective Sep. 14, 2010, and substantially higher earnings from the San José Power Station as the station operated normally throughout the year following the extended unplanned outages in 2009.

In 2009, TECO Guatemala’s net income was $38.6 million, compared to $36.9 million in 2008. TECO Guatemala’s full-year 2009 non-GAAP results, which exclude the $8.7 million gain on the sale of Navega were $29.9 million, compared to 2008 non-GAAP results of $46.5 million, which exclude $9.6 million of taxes related to the December cash repatriation. Results in 2009 reflected lower results at the San José Power Station due to unplanned outages for much of the first half of the year and lower capacity payments under the power sales contract as a result of lower availability due to the unplanned outages, partially offset by a $1.7 million net insurance recovery related to the unplanned outages. Results also reflected the reduction in the VAD tariff at EEGSA, which reduced 2009 earnings at TECO Guatemala by approximately $5.0 million. The effect of the VAD more than offset the benefit of 2.9% customer growth, higher energy sales, and cost control measures at EEGSA. The earnings from the DECA II unregulated EEGSA-affiliated companies, which provide, among other things, electricity transmission services, wholesale power sales to unregulated electric customers and engineering services, decreased due to the loss of the earnings from the telecommunications service provider, Navega, which was sold in the first quarter of 2009. The 2009 results for EEGSA and affiliated companies also included a $2.5 million benefit related to an adjustment to previously estimated year-end equity balances, compared to a similar $3.1 million benefit in 2008.

TECO Guatemala Outlook

In 2011, we expect normal operations for the Alborada and San José power stations. Earnings from the Alborada Power Station will be at the lower rates under the contract extension described above. TECO Guatemala’s results will reflect the absence of earnings from DECA II, which was sold in October 2010. Prior to the sale, DECA II contributed $13.1 million to 2010 net income at TECO Guatemala.

PARENT/OTHER

The cost for Parent/other in 2010 was $98.5 million, compared to $54.0 million in 2009. The 2010 non-GAAP cost for Parent & other was $59.9 million, which excluded a $33.5 million charge related to early retirement of TECO Energy debt, and a $6.0 million foreign tax credit valuation allowance as a result of the sale of DECA II based on estimated foreign source income and projected timing of the utilization of the net operating loss carry forwards, the $1.8 million benefit related to the recovery of fees paid for the previously sold McAdams Power station, and $0.9 million of final restructuring costs. Non-GAAP results in 2009 were $48.6 million which included a $2.6 million benefit from a sale of property by TECO Properties but excluded $1.6 million of restructuring cost and a $3.8 million charge associated with the sale of auction-rate securities held at TECO Energy parent (see the 2010 and 2009 Reconciliation of GAAP net income

 

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from continuing operations to non-GAAP results tables).

Non-GAAP cost in 2010 included $9.6 million of foreign tax credit and other tax valuation adjustments based on estimated foreign source income and projected timing of the utilization of the net operating loss carry forwards, and a $1.1 million charge to adjust deferred tax balances related to Medicare Part D subsidies as a result of the Patient Protection and Affordable Care Act enacted early in 2010. Results also included a $3.5 million unfavorable tax adjustment that offsets the favorable domestic production deduction at Tampa Electric due to TECO Energy’s consolidated net operating loss (NOL) position. Results also reflect $3.4 million lower interest expense as a result of debt restructuring and retirement.

In 2009, Parent/other cost was $54.0 million, compared to a cost of $55.2 million in 2008. Non-GAAP Parent/other cost was $48.6 million in 2009, compared to $45.8 million in 2008. Results in 2009 reflected a $2.6 million unfavorable valuation adjustment to foreign tax credits, a $1.5 million gain on the sale of a lease, the final asset held in a leveraged lease portfolio, and a $2.6 million benefit from a sale of property by TECO Properties. Results in 2009 also reflected negative tax return adjustments that normally occur, compared to 2008 when the tax return adjustments were favorable. Non-GAAP Parent/other cost in 2009 excluded $1.6 million of restructuring costs and a $3.8 million charge associated with the sale of student-loan securities held at TECO Energy parent (see the 2009 and 2008 Reconciliation of GAAP net income from continuing operations to non-GAAP results tables).

OTHER ITEMS IMPACTING NET INCOME

Other income (expense)

In 2010, Other income (expense) of $14.1 million included a $55.5 million charge related to early debt retirement; $13.1 million from DECA II prior to its sale, which was accounted for as an equity investment; and $38.4 million pretax gain on TECO Guatemala’s sale of its ownership interest in DECA II.

In 2009, Other income (expense) of $79.3 million reflected $68.5 million, which included the $18.3 million pretax gain on the sale of Navega, from the Guatemalan operations, which are accounted for as equity investments, and a net $3.3 million charge related to the sale of various investments.

In 2008, Other income (expense) of $100.7 million reflected $72.5 million of pretax income from the Guatemalan operations, which are accounted for as equity investments; $7.2 million of pretax interest income on invested cash balances; and $6.7 million of pretax income from the sale of right-of-way easements and a contract settlement related to future coal sales at TECO Coal.

AFUDC equity at Tampa Electric, which is included in Other income (expense), was $1.9 million, $9.3 million and $6.3 million in 2010, 2009 and 2008, respectively. AFUDC is expected to decrease in 2011 due to the completion of the installation of the fourth and final NOx control unit at the Big Bend Power Station in 2010 (see the Environmental Compliance and Liquidity, Capital Resources sections).

Interest Expense

In 2010, total interest expense was $231.3 million compared to $227.0 million in 2009 and $228.9 million in 2008. In 2010, interest expense increased due to higher debt balances for six months of the year (see the Financing Activity section), prior to the early retirement of TECO Energy and TECO Finance debt in December, and lower AFUDC debt at Tampa Electric, which is a credit to interest expense. In 2009, interest expense was reduced by lower interest rates on floating rate debt and higher AFUDC debt at Tampa Electric.

Interest expense is expected to be lower in 2011 due to the retirement of $236 million of TECO Energy and TECO Finance debt in December 2010, and the retirement of $64 million of TECO Energy debt at maturity in April 2011 (see the Liquidity, Capital Resources section).

Income Taxes

The provision for income taxes increased in 2010 primarily due to higher operating income, taxes on TECO Guatemala’s sale of its ownership interest in DECA II, and an increase to the foreign tax credit valuation allowance. The provision for income taxes increased in 2009 due to higher operating income, partially offset by lower foreign tax credit valuation allowances, lower taxes on cash repatriated from Guatemala, and increased depletion and AFUDC equity. Income tax expense as a percentage of income from continuing operations before taxes was 41.5% in 2010, 31.6% in 2009 and 36.8% in 2008. For 2011, we expect the effective tax rate to be in the range of 30% to 35%.

The cash payments for federal income taxes, as required by the federal Alternative Minimum Tax rules (AMT), state income taxes, foreign income taxes and payments (refunds) related to prior years’ audits totaled $5.5 million, $4.1 million, and $6.0 million in 2010, 2009, and 2008, respectively.

On Dec. 17, 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 was signed

 

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into law. The legislation provides 100% bonus depreciation for capital investments placed in service after Sep. 8, 2010 and through Dec. 31, 2011 and 50% bonus for equipment placed in service after Dec. 31, 2011 and through Dec. 31, 2012. Based on the company’s preliminary estimate, additional bonus depreciation will extend our NOL.

Due to the NOL carryforward position resulting from the disposition of the generating assets formerly held by TWG Merchant, cash tax payments for income taxes are limited to approximately 10% of the AMT rate. We expect future cash tax payments to be limited to a similar level reduced by AMT foreign tax credits and various state taxes. We currently expect to utilize these NOLs through 2015, at which time we expect to start using more than $195 million of AMT carryforward to limit future cash tax payments for federal income taxes to the level of AMT. We currently project cash tax payments of between $30 and $35 million over the next five years.

The utilization of the NOL and AMT carryforward are dependent on the generation of sufficient taxable income in future periods.

LIQUIDITY, CAPITAL RESOURCES

The table below sets forth the Dec. 31, 2010 consolidated liquidity and cash balances, the cash balances at the operating companies and TECO Energy parent, and amounts available under the TECO Energy/Finance and Tampa Electric Company credit facilities.

 

     Balances as of Dec. 31, 2010                
      Consolidated      Tampa Electric
Company
     Unregulated
Companies
     Parent  

(millions)

           

Credit facilities

   $ 675.0       $ 475.0       $ —         $ 200.0   

Drawn amounts/LCs

     19.4         12.7         —           6.7   
                                   

Available credit facilities

     655.6         462.3         —           193.3   

Cash and short-term investments

     82.3         3.7         38.9         39.7   
                                   

Total liquidity

   $ 737.9       $ 466.0       $ 38.9       $ 233.0   
                                   

In 2010, we met our cash flow needs primarily from internal sources. Cash from operations was $664 million. We paid dividends of $175 million in 2010, and capital expenditures were $490 million. Other sources of cash included $183 million of proceeds from the sale of businesses, primarily the sale of our ownership interest in DECA II for $181 million and $8 million from the sale of common stock, primarily through dividend reinvestment. Proceeds from the sale of DECA II, along with repatriated cash of $25 million and cash on hand were used to retire long-term debt. Net long-term debt declined $136 million representing debt retirement at TECO Energy parent and TECO Finance and a $75 million remarketing by Tampa Electric Company of tax-exempt notes previously held in lieu of redemption. Short-term debt declined $43 million.

In 2009, we met our cash flow needs primarily from a mix of internal sources supplemented with net borrowings of $57 million, of which $102 million represented notes issued by Tampa Electric Company. Cash from operations was $725 million. Other sources of cash included $32 million of proceeds from the sale of businesses, primarily the sale of our ownership interest in the Guatemalan telecommunications provider, Navega, $5 million from the sale of common stock, primarily through dividend reinvestment, and $16 million from the sale of student loan securities and other investments. We paid dividends of $171 million in 2009, and capital expenditures were $640 million.

In 2008, we met our cash needs primarily from a mix of internal sources and cash on hand at the beginning of the year, including cash held offshore which was repatriated in December 2008. We supplemented this with net borrowings of $102 million, of which $68 million represented borrowings under bank credit facilities. Cash from operations was $388 million in 2008.

Cash from Operations

In 2010, consolidated cash flow from operations was $664 million, which was positively impacted by $55 million associated with net recoveries of deferred costs, primarily fuel and purchased power, under FPSC-approved recovery clauses. Cash from operations reflects an $81 million contribution to the pension plans in 2010, which included a $47 million pre-funding of our 2011 required contribution. Cash from operations also reflects the benefit of our tax NOL position, which resulted in minimal cash payments for state and federal income taxes (see the Income Tax section).

We expect cash from operations in 2011 to be higher than the 2010 level. We expect higher net income in 2011, but due to the over-recovery of fuel and purchased power costs in 2010, we expect the net recoveries under various regulatory clauses to reduce cash from operations. In November 2010, the FPSC approved recovery clause rates that provide for refunds to customers of estimated 2010 net over-recoveries of fuel and purchased power over 12 months beginning Jan. 1,

 

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2011 (see the Regulation section). Like 2010, we expect our NOL carryforwards to result in minimal state and federal income tax payments in 2011 (see the Income Tax section).

Cash from Investing Activities

Our investing activities in 2010 resulted in a net use of cash of $296 million, including capital expenditures totaling $490 million. In 2010 we received $183 million representing the proceeds from the sale of businesses and other assets, primarily the sale of our ownership interest in DECA II.

We expect capital spending for the next several years to be below 2010 levels primarily due to the completion of the SeaCoast Gas Transmission, LLC (SeaCoast LLC) intrastate pipeline and the NOx control projects at Tampa Electric (see the Capital Expenditures section).

Cash from Financing Activities

Our financing activities in 2010 resulted in a net use of cash of $347 million. Major items included the net repayment of $189 million of TECO Parent and TECO Finance long-term debt, $75 million of proceeds from Tampa Electric Company’s remarketing of tax-exempt notes previously held in lieu of redemption, and the repayment of $43 million of short-term debt (see the Financing section). We paid $175 million in common stock dividends, and we received almost $8 million from the sale of common stock from our dividend reinvestment program and exercises of stock options.

In 2011, Tampa Electric Company expects to utilize internally generated funds, equity contributions from TECO Energy, and short-term borrowings under its credit facilities to support its capital spending program and for normal working capital fluctuations. We have $64 million of TECO Energy parent and TECO Finance notes maturing in 2011 which we expect to retire at maturity. See the Cash and Liquidity Outlook section below for a discussion of financing expectations in 2011 and beyond.

Cash and Liquidity Outlook

In general, we target to maintain consolidated liquidity (unrestricted cash on hand plus undrawn credit facilities) of at least $500 million. At Dec. 31, 2010 our consolidated liquidity was $738 million, consisting of $466 million at Tampa Electric Company, $233 million at TECO Energy parent and $39 million at the other operating companies.

We expect our sources of cash in 2011 to include cash from operations at levels above 2010, due in large part to higher net income from the operating companies and lower pension contributions, due to prefunding the expected 2011 contribution in 2010, partially offset by lower net recoveries under various regulatory clauses in 2011 as described above. We plan to use cash generated in 2011 to fund capital spending estimated at $440 million, for dividends to shareholders and to retire maturing debt.

Tampa Electric Company expects to utilize cash from operations and equity contributions from TECO Energy to support its capital spending program, supplemented with minimal incremental utilization of its credit facilities. Our credit facilities contain certain financial covenants (see Covenants in Financing Agreements section). Although we expect the normal utilization of our credit facilities to be low, we estimate that we could fully utilize the total available capacity under our facilities in 2011 and remain within the covenant restrictions.

Beyond 2011, our long-term debt maturities for TECO Energy parent and TECO Finance total $200 million in 2015, $250 million in 2016, $300 million in 2017 and $300 million in 2020. Tampa Electric Company has two series of notes totaling $372 million maturing in 2012 and will need to issue replacement debt to fund some or all of those maturities. The existing bank credit facilities for both Tampa Electric Company and TECO Energy/TECO Finance expire in 2012. We expect to renew these facilities in late 2011 under similar terms, but at higher cost.

Our expected cash flow could be affected by variables discussed in the individual operating company sections, such as customer growth and usage changes at our regulated businesses, and coal margins. In addition, actual fuel and other regulatory clause net recoveries will typically vary from those forecasted; however, the differences are generally recovered within the next calendar year. It is possible, however, that unforeseen cash requirements and/or shortfalls, or higher capital spending requirements could cause us to fall short of our liquidity target (see the Risk Factors section).

TECO Energy expects to continue to make equity contributions to Tampa Electric Company in order to support the capital structure and financial integrity of the utilities. Tampa Electric Company expects to fund its capital needs with a combination of internally generated cash and equity contributions from us. Through 2015, we expect to realize significant cash benefits from the utilization of net operating loss carryforwards generated in 2004 and 2005 upon the disposition of merchant power assets to reduce federal and certain state income taxes. We currently project cash tax payments between $30 and $35 million over the next five years.

As a result of our significant reduction of parent debt, and reduced business risk, we have improved our debt credit ratings and ratings outlooks (see Credit Ratings section). It is our intention to continue to improve our financial profile, with a goal of achieving additional ratings improvements. In the unlikely event Tampa Electric Company’s ratings were

 

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downgraded to below investment grade counterparties to our derivative instruments could request immediate payment or full collateralization of net liability positions. If the credit risk-related contingent features underlying these derivative instruments were triggered as of Dec. 31, 2010, we could have been required to post additional collateral or settle existing positions with counterparties totaling $29.7 million, which are Tampa Electric Company positions. In addition, credit provisions in long-term gas transportation agreements of Tampa Electric and PGS would give the transportation providers the right to demand collateral which we estimate to be approximately $64.4 million. None of our credit facilities or financing agreements have ratings downgrade covenants, which would require immediate repayment or collateralization; however, in the event of a downgrade, our interest expense could be higher.

SHORT-TERM BORROWING

Credit Facilities

At Dec. 31, 2010 and 2009, the following credit facilities and related borrowings existed:

 

     Dec. 31, 2010      Dec. 31, 2009  

(millions)

   Credit
Facilities
     Borrowings
Outstanding
    Letters of
Credit
Outstanding
     Credit
Facilities
     Borrowings
Outstanding
    Letters of
Credit
Outstanding
 

Tampa Electric

               

5-year facility

   $ 325.0       $ 5.0      $ 0.7       $ 325.0       $ 55.0      $ 0.7   

1-year accounts receivable facility

     150.0         7.0        —           150.0         —          —     

TECO Finance :

               

5-year facility

     200.0         —          6.7         200.0         —          6.9   
                                                   

Total

   $ 675.0       $ 12.0 (1)    $ 7.4       $ 675.0       $ 55.0 (1)    $ 7.6   
                                                   

 

(1) Borrowings outstanding are reported as notes payable.

These credit facilities, including the one-year accounts receivable facility which was renewed in February 2011, require commitment fees ranging from 7.0 to 35.0 basis points. The weighted average interest rates on outstanding notes payable under the credit facilities at Dec. 31, 2010 and 2009 were 0.64% and 0.66%, respectively.

At Dec. 31, 2010, TECO Finance had a $200 million bank credit facility in place guaranteed by TECO Energy with a maturity date in May 2012. Tampa Electric Company had a bank credit facility totaling $325 million, also maturing in May 2012. In addition, Tampa Electric Company had a $150 million accounts receivable securitized borrowing facility which was renewed in February 2011 with a maturity date of February 2012. The TECO Finance and Tampa Electric Company bank credit facilities include sub-limits for letters of credit of $200 million and $50 million, respectively. At Dec. 31, 2010, the TECO Finance credit facility was undrawn and $6.7 million of letters of credit were outstanding. At Dec. 31, 2010, $12.0 million was drawn on the Tampa Electric Company credit facilities and $0.7 million of letters of credit were outstanding.

 

     2010 Credit Facility Utilization         

(millions)

   Maximum drawn
amount
     Minimum drawn
amount
     Average drawn
amount
     Average
interest rate
 

TECO Finance

   $ 35.0         —         $ 3.0         0.85

Tampa Electric

   $ 102.0         —         $ 26.3         0.71
                                   

At current ratings, TECO Finance’s and Tampa Electric Company’s bank credit facilities require commitment fees of 12.5 basis points and 7.0 basis points, respectively, and drawn amounts are charged interest at LIBOR plus 55.0 – 60.0 basis points and 35.0 – 40.0 basis points, respectively. At Dec. 31, 2010, the LIBOR interest rate was 0.26%.

Tampa Electric Company and TEC Receivables Corp. (TRC), a wholly-owned subsidiary of Tampa Electric Company, have a $150 million accounts receivable collateralized borrowing facility. Under this facility, Tampa Electric Company sells and/or contributes to TRC all of its receivables for the sale of electricity or gas to its customers and related rights. The receivables are sold by Tampa Electric Company to TRC at a discount, which was initially 2%. The discount is subject to adjustment for future sales to reflect changes in prevailing interest rates and collection experience. TRC is consolidated in the financial statements of Tampa Electric Company and TECO Energy.

 

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Under a Loan and Servicing Agreement, TRC may borrow up to $150 million to fund its acquisition of the receivables under the facility, and TRC secures such borrowings with a pledge of all of its assets, including the receivables. Tampa Electric Company acts as the servicer to service the collection of the receivables. TRC pays program and liquidity fees based on Tampa Electric Company’s credit ratings, which total 70 basis points at its current ratings under its renewed facility. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, or under certain circumstances upon a change of accounting rules applicable to the lenders, in which case the rates will be at an interest rate equal to, at Tampa Electric Company’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the London interbank deposit rate (if available) plus a margin. The facility includes the following financial covenants: (1) at each quarter-end, Tampa Electric Company’s debt-to-capital ratio, as defined in the agreement, must not exceed 65%; and (2) certain dilution and delinquency ratios with respect to the receivables (see the Covenants in Financing Agreements section). Tampa Electric Company renewed this facility Feb. 18, 2011 with a Feb. 17, 2012 maturity date (see Note 25 to the TECO Energy Consolidated Financial Statements).

Covenants in Financing Agreements

In order to utilize their respective bank credit facilities, TECO Energy, TECO Finance and Tampa Electric Company must meet certain financial tests as defined in the applicable agreements (see the Credit Facilities section). In addition, TECO Energy, TECO Finance, Tampa Electric Company, and other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Dec. 31, 2010, TECO Energy, TECO Finance, Tampa Electric Company, and the other operating companies were in compliance with all required financial covenants. The table that follows lists the significant financial covenants and the performance relative to them at Dec. 31, 2010. Reference is made to the specific agreements and instruments for more details.

TECO Energy Significant Financial Covenants

(millions, unless otherwise indicated)  

Instrument

  

Financial Covenant(1)

  

Requirement/Restriction

   Calculation
at Dec.  31, 2010
 

Tampa Electric Company

        

Credit facility(2)

   Debt/capital    Cannot exceed 65%      49.1%   

Accounts receivable credit facility(2)

   Debt/capital    Cannot exceed 65%      49.1%   

6.25% senior notes

  

Debt/capital

Limit on liens(3)

  

Cannot exceed 60%

Cannot exceed $700

    

 
 

49.1%

$0 liens
outstanding

  

  
  

Insurance agreement relating to certain pollution bonds

   Limit on liens(3)    Cannot exceed $441 (7.5% of net assets)     
 
$0 liens
outstanding
  
  

TECO Energy/TECO Finance

        

Credit facility(2)

   EBITDA/interest(4)    Minimum of 2.6 times      4.6 times   

TECO Energy 6.75% notes and TECO Finance 6.75% notes

   Restrictions on secured debt(5)    (6)      (6)   

 

(1) As defined in each applicable instrument.
(2) See Note 6 to the TECO Energy Consolidated Financial Statements for a description of the credit facilities.
(3) If the limitation on liens is exceeded the company is required to provide ratable security to the holders of these notes.
(4) EBITDA generally represents EBIT before depreciation and amortization. However, the term is subject to the definition prescribed under the relevant agreement.
(5) These limitations would not include first mortgage bonds of Tampa Electric Company if any were outstanding.
(6) The indentures for these notes contain restrictions which limit secured debt of TECO Energy if secured by Principal Property or Capital Stock or indebtedness of directly held subsidiaries (with exceptions as defined in the indentures) without equally and ratably securing these notes.

Credit Ratings of Senior Unsecured Debt at Dec. 31, 2010

 

     

Standard & Poor’s

   Moody’s    Fitch
Tampa Electric Company    BBB     Baa1    BBB+
TECO Energy/TECO Finance    BBB-    Baa3    BBB- 

On Oct. 22, 2010, Fitch Ratings placed TECO Energy, TECO Finance and Tampa Electric Company on Rating Watch Positive following the announcement of the sale of DECA II (see TECO Guatemala section). The Rating Watch Positive reflects Fitch’s expectation that previously anticipated parent level debt reduction would be accelerated by the DECA II sale and the use of the resulting cash proceeds to retire parent level debt (see the Financing Activities section). This followed Fitch’s revision of the long-term Rating Outlook to positive on Jun. 25, 2010.

Standard & Poor’s, Moody’s and Fitch describe credit ratings in the BBB or Baa category as representing adequate capacity for payment of financial obligations. The lowest investment grade credit ratings for Standard & Poor’s is BBB-,

 

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for Moody’s is Baa3 and for Fitch is BBB-; thus all three credit rating agencies assign TECO Energy, TECO Finance and Tampa Electric Company’s senior unsecured debt investment grade ratings.

A credit rating agency rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Our access to capital markets and cost of financing, including the applicability of restrictive financial covenants, are influenced by the ratings of our securities. In addition, certain of Tampa Electric Company’s derivative instruments contain provisions that require Tampa Electric Company’s debt to maintain an investment grade credit ratings. See Note 12 to the TECO Energy Consolidated Financial Statements. The credit ratings listed above are included in this report in order to provide information that may be relevant to these matters and because downgrades, if any, in credit ratings may affect our ability to borrow and may increase financing costs, which may decrease earnings (see the Risk Factors section). These credit ratings are not necessarily applicable to any particular security that we may offer and therefore should not be relied upon for making a decision to buy, sell or hold any of our securities.

Summary of Contractual Obligations

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

Contractual Cash Obligations at Dec. 31, 2010

 

(millions)

   Payments Due by Period  
   Total      2011      2012      2013      2014-
2015
     After 2015  

Long-term debt (1)

                 

Recourse

   $ 3,184.4       $ 67.1       $ 375.0       $ 60.7       $ 366.6       $ 2,315.0   

Non-recourse (2)

     44.7         11.2         11.2         11.2         11.1         —     

Operating leases/rentals (3)

     117.5         17.3         14.3         12.0         23.5         50.4   

Net purchase obligations/commitments (4)

     201.7         74.4         40.5         30.5         56.2         0.1   

Interest payment obligations

     1,871.0         179.4         172.6         160.1         279.0         1,079.9   

Pension plans (5)

     171.4         —           35.7         47.1         88.6         —     
                                                     

Total contractual obligations

   $ 5,590.7       $ 349.4       $ 649.3       $ 321.6       $ 825.0       $ 3,445.4   
                                                     

 

(1) Includes debt at TECO Energy, TECO Finance, Tampa Electric, PGS and the other operating companies (see Note 7 to the TECO Energy Consolidated Financial Statements for a list of long-term debt and the respective due dates).
(2) Reflects non-recourse project debt of the San José power project.
(3) Excludes payment obligations under contractual agreements of Tampa Electric and PGS for fuel, fuel transportation and power purchases which are recovered from customers under regulatory clauses approved by the FPSC annually (see the Regulation section). One of these agreements, in accordance with the accounting guidance for determining whether an arrangement contains a lease, has been determined to contain a lease (see Note 12 to the TECO Energy Consolidated Financial Statements)
(4) Reflects those contractual obligations and commitments considered material to the respective operating companies, individually. At the end of 2010, these commitments include Tampa Electric’s outstanding commitments for major projects and long-term capitalized maintenance agreements for its combustion turbines.
(5) The total includes the estimated minimum required contributions to the qualified pension plan as of the measurement date. Future contributions are included but they are subject to annual valuation reviews, which may vary significantly due to changes in interest rates, discount rate assumptions, plan asset performance, which is affected by stock market performance, and other factors (see Liquidity, Capital Resources section and Note 5 to the TECO Energy Consolidated Financial Statements).

Summary of Contingent Obligations

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

 

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Contingent Obligations at Dec. 31, 2010

 

(millions)

   Commitment Expiration  
          Total      2011      2013      2013      2014 -
2015
     After
2015(1)
 

Letters of credit

      $ 7.4       $ —         $ —         $ —         $ —         $ 7.4   

Guarantees

     Fuel purchase(2)         129.7         —           —           —           —           129.7   
     Other         5.4         —           —           —           —           5.4   
                                                        

Total contingent obligations

      $ 142.5       $ —         $ —         $ —         $ —         $ 142.5   
                                                        
(1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2015.
(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements.

Capital Expenditures

 

      Actual      Forecast  

(millions)

   2010      2011      2012      2013 –
2015
     2011 – 2015
Total
 

Tampa Electric

              

Transmission

   $ 40       $ 45       $ 40       $ 90       $ 175   

Distribution

     90         90         90         295         475   

Generation

     135         135         140         360         635   

Other

     20         30         35         115         180   

NOx control projects

     15         —           —           —           —     

Other environmental

     5         25         40         45         110   
                                            

Tampa Electric total

     305         325         345         905         1,575   

Net cash effect of accruals and Retentions

     25         —           —           —           —     
                                            

Tampa Electric net

     330         325         345         905         1,575   
                                            

PGS

     60         60         60         180         300   

Unregulated companies(1)

     100         55         60         155         270   
                                            

Total

   $ 490       $ 440       $ 465       $ 1,240       $ 2,145   
                                            

 

(1) Represents the capital expenditures of TECO Coal, SeaCoast LLC and the consolidated operations of TECO Guatemala.

TECO Energy’s 2010 capital expenditures of $490 million included $330 million at Tampa Electric, including $3 million of AFUDC – debt and equity, and $25 million of amounts paid in 2010 but incurred in a prior period. Capital expenditures at PGS were $60 million in 2010. Tampa Electric’s capital expenditures in 2010 were primarily for equipment and facilities to meet modest customer growth, generating equipment maintenance, environmental compliance, and completion of the final NOx control project (see the Environmental Compliance section). Capital expenditures for PGS were approximately $30 million for system expansion and approximately $30 million for maintenance of the existing system. TECO Coal’s capital expenditures included $30 million primarily for normal mining equipment replacement, and $20 million for new mine development. SeaCoast LLC invested approximately $50 million for the construction of the SeaCoast LLC natural gas pipeline in northeast Florida, which was completed in late 2010. SeaCoast LLC, an indirect wholly-owned Subsidiary of TECO Energy, owns a 24 mile intrastate natural gas pipeline in northeast Florida that began serving the Jacksonville Electric Authority Greenland Energy Center in late 2010 under a long-term contract. Currently the Greenland Energy Center is the sole customer of SeaCoast LLC; however, we are seeking other customers for the existing capacity on this pipeline.

TECO Energy estimates capital spending for ongoing operations to be $440 million for 2011 and approximately $1.7 billion during the 2012 – 2015 period.

For 2011, Tampa Electric expects to spend $325 million. For the transmission and distribution systems Tampa Electric expects to spend $135 million in 2011, including approximately $90 million for normal transmission and distribution system expansion and reliability, and $30 million for transmission and distribution system storm hardening. Capital expenditures for the existing generating facilities of $135 million include approximately $25 million for repair and refurbishments of combustion turbines under long-term agreements with equipment manufacturers, approximately $50 million for generating unit outages, $15 million for a reclaimed water pipeline to eliminate ground water usage at the Polk Power Station, and $45 million for other improvements and refurbishments to generating units. In addition, Tampa Electric expects to spend $25 million for environmental compliance programs in 2011.

In the 2012 – 2015 period, Tampa Electric expects to spend $35 million for the completion of the reclaimed water

 

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pipeline project at the Polk Power Station. Capital spending for environmental compliance is expected to average approximately $20 million annually in the same period. In addition to the above amounts, Tampa Electric expects to spend approximately $285 million annually to support normal system growth and reliability in the 2012 – 2015 period. This level of ongoing capital expenditures reflects the costs for materials and contractors, long-term regulatory requirements for storm hardening, and an active program of transmission and distribution system upgrades which will occur over the forecast period. These programs and requirements include: approximately $20 million annually for repair and refurbishments of combustion turbines under long-term agreements with equipment manufacturers; average annual expenditures of more than $90 million to support generating unit availability and reliability; average annual expenditures of $35 million for general infrastructure to support customers; average annual expenditures of more than $25 million for transmission and distribution system storm hardening; approximately $30 million annually for transmission system reliability and capacity improvements; and an average of approximately $85 million annually for distribution system reliability and to meet the expected customer growth.

Capital expenditures for PGS are expected to be about $60 million in 2011 and $240 million during the 2012 – 2015 period. Included in these amounts is an average of approximately $35 million annually for projects associated with customer growth and system expansion. The remainder represents capital expenditures for ongoing renewal, replacement and system safety.

The unregulated companies expect to invest $55 million in 2011 and $215 million during the 2012 – 2015 period. Included in these amounts are expenditures for coal mine development to maintain production, compliance with new safety requirements under the MINER Act, and for normal coal mining equipment renewal and replacement at TECO Coal, and capital to support generating unit reliability at TECO Guatemala.

Tampa Electric – Generating Capacity Additions

In 2009, Tampa Electric completed the construction of five peaking capacity combustion turbines at the Bayside and Big Bend power stations. These units were used to meet the summer peak demand requirements in 2009 and the new winter peak experienced in January 2010. One combustion turbine at each of the facilities is configured to meet the North American Electric Reliability Council (NERC) black start requirements for system reliability.

Due to the 2008 and 2009 financial crisis and the slowdown in the Florida and national economies, Tampa Electric has deferred new baseload capacity until beyond the 2015 forecast period. Tampa Electric may require peaking capacity in the 2013 period, after the expiration of the purchased power agreement with the Hardee Power Station in Central Florida. If demand growth resumes and additional generating capacity is required, Tampa Electric may construct this additional peaking capacity or seek to purchase power rather than build based on the economics (see the Tampa Electric and Regulation sections). If Tampa Electric builds this capacity, capital expenditures would start in 2012.

If the U.S. Congress or the Florida Legislature enacted a national or Florida Renewable Energy Portfolio Standard (RPS), the need for additional capital spending for renewable generating resources to meet the requirements of a RPS is likely but not yet defined (see the Environmental Compliance section). Depending on the final federal or state rules, which may be enacted in 2011, Tampa Electric may need to invest capital to develop additional sources of renewable power generation.

The forecast of capital expenditures shown above are based on our current estimates and assumptions for normal maintenance capital at the operating companies; capital expenditures to support normal system reliability and growth at Tampa Electric and PGS; the programs for transmission and distribution system storm hardening and transmission system reliability requirements; and incremental investments above normal maintenance capital to expand the PGS system and production capacity at TECO Coal. Actual capital expenditures could vary materially from these estimates due to changes in costs for materials or labor or changes in plans (see the Risk Factors section).

Financing Activity

Our year-end 2010 consolidated capital structure was 60% debt and 40% common equity. The debt-to-total-capital ratio has improved significantly over the past four years, primarily due to the repayment of more than $900 million of parent and parent guaranteed debt, consisting of $765 million in 2007 and a net $189 million in 2010, as well as the increase in retained earnings. At Dec. 31, 2010, Tampa Electric Company’s year-end capital structure was 49% debt and 51% common equity.

In 2010, we raised $3.6 million of equity primarily through our dividend reinvestment plan.

In December 2010, Tampa Electric Company completed an exchange offer (the Exchange Offer) which resulted in the exchange of $278.5 million principal amount of Tampa Electric Company notes for $278.5 million principal amount of Tampa Electric Company 5.40% Notes due 2021. The Exchange Offer resulted in the exchange of $131.5 million principal amount of Tampa Electric Company 6.875% Notes due 2012 and $147.0 million principal amount of Tampa Electric Company 6.375% Notes due 2012 for $278.5 million principal amount of Tampa Electric Company 5.40% Notes due 2021. After the Exchange Offer, $118.5 million principal amount of Tampa Electric Company 6.875% Notes due 2012 and $253.0 million principal amount of Tampa Electric Company 6.375% Notes due 2012 remain outstanding.

 

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In December 2010, TECO Energy and TECO Finance redeemed $73.2 million and $163.1 million, respectively, of 7.0% notes due May 1, 2012. The redemption price was equal to $1,089.73 per $1,000 principal amount of notes redeemed, plus accrued and unpaid interest on the redeemed notes up to the redemption date. In connection with this transaction, a $13.2 million charge for premiums and fees was recorded at TECO Energy Parent & other (see the 2010 Reconciliation of GAAP net income from continuing operations to non-GAAP results table).

In November 2010, the Polk County Industrial Development Authority (PCIDA) issued $75.0 million Solid Waste Disposal Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010, in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. Proceeds of the bonds were used to redeem $75.0 million PCIDA Solid Waste Disposal Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 bonds, which previously had been in auction rate mode and were held by Tampa Electric Company since Mar. 26, 2008. The Series 2010 bonds bear interest at 1.50% per annum and are subject to mandatory tender for purchase on Mar. 1, 2011. Tampa Electric Company entered into a Loan and Trust Agreement with the PCIDA, as issuer, and The Bank of New York Trust Company, N.A., as trustee, in connection with the issuance of the Series 2010 Bonds. Tampa Electric Company is responsible for payment of the interest and principal associated with the bonds.

On Mar. 26, 2008, Tampa Electric Company purchased in lieu of redemption $75.0 million PCIDA Solid Waste Disposal Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 and $20 million Hillsborough County Industrial Development Authority (HCIDA) Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007C (collectively, the “2007 Bonds”). After the Nov. 15, 2010 issuance of the Series 2010 PCIDA Bonds, $20 million of bonds purchased in lieu of redemption were held by the trustee at the direction of Tampa Electric Company as of Dec. 31, 2010 (the “Held Bonds”) to provide an opportunity to evaluate refinancing alternatives. The Held Bonds effectively offset the outstanding debt balances and are presented net on the balance sheet.

In April 2010, TECO Energy redeemed $100 million aggregate principal amount of its 7.2% Notes due 2011. The redemption price was equal to $1,066.38 per $1,000 principal amount of notes redeemed, plus accrued and unpaid interest on the redeemed notes up to the redemption date. In connection with this transaction, a $4.1 million charge for premiums and fees was recorded at TECO Energy Parent & other (see the 2010 Reconciliation of GAAP net income from continuing operations to non-GAAP results table).

In April 2010, TECO Energy redeemed all of the outstanding $100 million aggregate principal amount of its Floating Rate Notes due 2010. The redemption price was equal to 100% of the principal amount of notes redeemed, plus accrued and unpaid interest on the redeemed notes up to the redemption date.

In March, 2010, TECO Energy and TECO Finance completed debt tender offers which resulted in the purchase of $70 million principal amount of TECO Energy notes for cash and approximately $230 million principal amount of TECO Finance notes for cash. The tender offers resulted in the purchase and retirement of: $43.0 million principal amount of TECO Energy 7.2% Notes due 2011; $27.0 million principal amount of TECO Energy 7.0% Notes due 2012; $156.9 million principal amount of TECO Finance 7.2% Notes due 2011; $73.1 million principal amount of TECO Finance 7.0% Notes due 2012. In connection with this transaction, a $16.2 million charge for premiums and fees was recorded at TECO Energy Parent & other (see the 2010 Reconciliation of GAAP net income from continuing operations to non-GAAP results table).

In March 2010, TECO Finance, Inc. issued $250 million aggregate principal amount of 4.00% Notes due Mar. 15, 2016 and $300 million aggregate principal amount of 5.15% Notes due Mar. 15, 2020. The 2016 Notes were priced at 99.594% of the principal amount to yield 4.077% to maturity, and the 2020 Notes were priced at 99.552% of the principal amount to yield 5.208% to maturity. TECO Finance is a wholly-owned subsidiary of TECO Energy whose business activities consist solely of providing funds to TECO Energy for its diversified activities. The TECO Finance notes are fully and unconditionally guaranteed by TECO Energy.

The offering resulted in net proceeds to TECO Finance (after deducting underwriting discounts and commissions and estimated offering expenses) of $543.5 million. TECO Finance used a portion of these net proceeds to fund the cash purchase of the TECO Energy and TECO Finance notes tendered in March 2010 (see “TECO Energy, Inc. and TECO Finance, Inc. Tender Offers” described above) and to fund the redemptions of the TECO Energy Floating Rate Notes due 2010 and 7.20% Notes due 2011 in April 2010.

In July 2009, Tampa Electric Company completed an offering of $100 million aggregate principal amount of 6.10%

 

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Notes due May 15, 2018. These notes were sold at 102.988% of par. The offering resulted in net proceeds (after deducting underwriting discounts and commissions and estimated offering expenses) of $102.0 million. Net proceeds were used to repay short-term debt and for general corporate purposes.

Effective Jan. 1, 2010, new accounting standards for consolidations amended the determination of the primary beneficiaries for variable interest entities. As a result of adopting these standards, TECO Guatemala, Inc., a wholly-owned subsidiary of TECO Energy, was determined to be the primary beneficiary of, and therefore required to consolidate, both the TCAE and CGESJ projects in Guatemala. The consolidation resulted in a net $44.4 million increase of non-recourse debt.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of consolidated financial statements requires management to make various estimates and assumptions that affect revenues, expenses, assets, liabilities, and the disclosure of contingencies. The policies and estimates identified below are, in the view of management, the more significant accounting policies and estimates used in the preparation of our consolidated financial statements. These estimates and assumptions are based on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and judgments under different assumptions or conditions. See Note 1 to the TECO Energy Consolidated Financial Statements for a description of our significant accounting policies and the estimates and assumptions used in the preparation of the consolidated financial statements.

Deferred Income Taxes

We use the liability method in the measurement of deferred income taxes. Under the liability method, we estimate our current tax exposure and assess the temporary differences resulting from differing treatment of items, such as depreciation for financial statement and tax purposes. These differences are reported as deferred taxes measured at current rates in the consolidated financial statements. Management reviews all reasonably available current and historical information, including forward-looking information, to determine if it is more likely than not that some or all of the deferred tax asset will not be realized. If we determine that it is likely that some or all of a deferred tax asset will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized.

At Dec. 31, 2010, we had net deferred income tax assets of $57.3 million, attributable primarily to property-related items, alternative minimum tax credit carryforwards, operating loss carryforwards, foreign tax credits and a valuation allowance. Based primarily on historical income levels and the company’s expectations for steady future earnings growth, management has determined that the net deferred tax assets recorded at Dec. 31, 2010 will be realized in future periods.

We believe that the accounting estimate related to deferred income taxes, and any related valuation allowance, is a critical estimate for the following reasons: 1) realization of the deferred tax asset is dependent upon the generation of sufficient taxable income, both operating and capital, in future periods; 2) a change in the estimated valuation reserves could have a material impact on reported assets and results of operations; and 3) administrative actions of the IRS or the U.S. Treasury or changes in law or regulation could change our deferred tax levels, including the potential for elimination or reduction of our ability to utilize the deferred tax assets (see Note 4 to the TECO Energy Consolidated Financial Statements).

The Financial Accounting Standards Board (FASB) has guidance that prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. See further discussion of uncertainty in income taxes in Note 4 to the TECO Energy Consolidated Financial Statements.

Employee Postretirement Benefits

We sponsor a defined benefit pension plan (pension plan) that covers substantially all of our employees. In addition, we have unfunded non-qualified, non-contributory supplemental executive retirement benefit plans available to certain members of senior management. Several statistical and other factors, which attempt to anticipate future events, are used in calculating the expense and liability related to these plans. Key factors include assumptions about the expected rates of return on plan assets, salary increases and discount rates. These factors are determined by us within certain guidelines and with the help of external consultants. We consider market conditions, including changes in investment returns and interest rates, in making these assumptions.

We believe that the accounting related to employee postretirement benefits is a critical accounting estimate for the following reasons: 1) a change in the estimated benefit obligation could have a material impact on reported assets, accumulated other comprehensive income and results of operations; and 2) changes in assumptions could change our annual pension funding requirements, having a significant impact on our annual cash requirements.

Pension plan assets (plan assets) are invested in a mix of equity and fixed income securities. The expected return on assets assumption was based on expectations of long-term inflation, real growth in the economy, fixed income spreads and equity premiums consistent with our portfolio, with provision for active management and expenses paid from the trust. The discount rate assumption is based on a cash flow matching technique developed by our outside actuaries and reflects

 

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current economic conditions. This technique matches the yields from high-quality (AA-rated, non-callable) corporate bonds to the company’s projected cash flows for the pension plan to develop a present value that is converted to a discount rate assumption, which is subject to change each year. The compensation increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases. Holding all other assumptions constant, a 1% decrease in the assumed rate of return on plan assets would have decreased 2010 net income by approximately $4.4 million. Likewise, a 1% decrease in the discount rate assumption would have resulted in an approximately $5.3 million decrease in 2010 net income. For 2011, a 1% decrease in the discount rate assumption would result in an approximately $3.2 million increase in the expected pension cost. A 1% decrease in the assumed rate of return on plan assets would result in an approximately $5.0 million increase in expected pension cost.

Unrecognized actuarial gains and losses are being recognized over a period of up to 9 years, which represents the expected remaining service life of the employee group. Unrecognized actuarial gains and losses arise from several factors including experience and assumption changes in the obligations and from the difference between expected return and actual returns on plan assets. These unrecognized gains and losses will be systematically recognized in future net periodic pension expense in accordance with applicable accounting guidance for pensions. Our policy is to fund the plan based on the required contribution determined by our actuaries within the guidelines set by the Employee Retirement Income Security Act of 1974 (ERISA), as amended.

In addition, we currently provide certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 who meet certain service requirements. In March 2010, the Patient Protection and Affordability Care Act and a companion bill, the Health Care and Education Reconciliation Act, combined the Health Care Reform Acts, were signed into law. Among other things, both acts reduce the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TECO Energy reduced its deferred tax asset by $6.4 million and recorded a corresponding charge of $1.1 million and a regulatory tax asset of $5.3 million.

Additionally, the Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy does not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase its postretirement benefit obligation. Accordingly, a re-measurement of TECO Energy’s postretirement benefit obligation is not required at this time. However, TECO Energy will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position.

The key assumptions used in determining the amount of obligation and expense recorded for postretirement benefits other than pension (OPEB), under the applicable accounting guidance, include the assumed discount rate and the assumed rate of increases in future health care costs. In 2009 we elected to begin determining the discount rate for the OPEB using that individual plan’s projected benefit cash flow rather than using the same discount rate that was determined for the pension plan. In estimating the health care cost trend rate, we consider our actual health care cost experience, future benefit structures, industry trends, and advice from our outside actuaries. We assume that the relative increase in health care cost will trend downward over the next several years, reflecting assumed increases in efficiency in the health care system and industry-wide cost containment initiatives. In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (MMA) was enacted. MMA established a prescription drug benefit under Medicare, known as Medicare Part D, and a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription benefit, which is at least actuarially equivalent to Medicare Part D. In May 2004, the FASB issued guidance that required: 1) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and 2) certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits.

We adopted the guidance retroactive to the second quarter of 2004 for benefits provided that we believe to be actuarially equivalent to Medicare Part D. The expected subsidy reduced the accumulated postretirement benefit obligations (APBO) at Dec. 31, 2010 by $35.3 million and increased net income for 2010 by $1.8 million. In 2010, we filed for and received a Part D subsidy of $0.8 million for the first three quarters of 2010. Payments for the fourth quarter of 2010 have not been received yet. The Health Care Reform Acts eliminated the tax-free status of those subsidies beginning in 2013.

The assumed health care cost trend rate for medical costs was 8.0% in 2010 and decreases to 4.50% in 2023 and thereafter. A 1% increase in the health care trend rates would have produced a 3.1% increase in the aggregate service and interest cost for 2010, which would have decreased net income $0.5 million, and a 3.8% increase in the accumulated postretirement benefit obligation as of Dec. 31, 2010, the measurement date.

A 1% decrease in the health care trend rates would have produced a 3.2% decrease in the aggregate service and interest

 

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cost for 2010, which would have increased net income $0.4 million, and a 3.2% decrease in the accumulated postretirement benefit obligation as of Dec. 31, 2010, the measurement date.

The actuarial assumptions we used in determining our pension and OPEB retirement benefits may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, or longer or shorter life spans of participants. While we believe that the assumptions used are appropriate, differences in actual experience or changes in assumptions may materially affect our financial position or results of operations.

See the discussion of employee postretirement benefits in Note 5 to the TECO Energy Consolidated Financial Statements.

Evaluation of Assets for Impairment

Long-Lived Assets

In accordance with accounting guidance for long-lived assets, we assess whether there has been an other-than-temporary impairment of our long-lived assets and certain intangibles held and used by us when such indicators exist. We annually review all long-lived assets in the last quarter of each year to ensure that any gradual change over the year and the seasonality of the markets are considered when determining which assets require an impairment analysis. We believe the accounting estimates related to asset impairments are critical estimates for the following reasons: 1) the estimates are highly susceptible to change, as management is required to make assumptions based on expectations of the results of operations for significant/indefinite future periods and/or the then current market conditions in such periods; 2) markets can experience significant uncertainties; 3) the estimates are based on the ongoing expectations of management regarding probable future uses and holding periods of assets; and 4) the impact of an impairment on reported assets and earnings could be material. Our assumptions relating to future results of operations or other recoverable amounts are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. Our expectations regarding uses and holding periods of assets are based on internal long-term budgets and projections, which give consideration to external factors and market forces, as of the end of each reporting period. The assumptions made are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities.

At Dec. 31, 2010, there were no indications of impairment for any of the company’s long-lived assets.

Goodwill

Under the accounting guidance for goodwill, goodwill is not subject to amortization. Rather, goodwill is subject to an annual (or more frequently if events and circumstances indicate a possible impairment) assessment for impairment at the reporting unit level. Reporting units are generally determined as one level below the operating segment level; reporting units with similar characteristics are grouped for the purpose of determining the impairment, if any, of goodwill and other intangible assets.

At Dec. 31, 2010, the company had $55.4 million of goodwill on its balance sheet, which is reflected in the TECO Guatemala segment. This goodwill balance arose from the purchase of multiple entities as a result of the company’s investments in its San José and Alborada power plants ($52.3 million and $3.1 million, respectively). Since these two investments are one level below the operating segment level, discrete cash flow information is available, and management regularly reviews their operating results separately. This is the reporting unit level at which potential impairment is tested. At Dec. 31, 2010, there was no impairment of this goodwill.

Regulatory Accounting

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

As a result of regulatory treatment and corresponding accounting treatment, we expect that the impact on utility costs and required investment associated with future changes in environmental regulations would create regulatory assets. Current regulation in Florida allows utility companies to recover from customers prudently incurred costs (including, for required capital investments, depreciation and a return on invested capital) for compliance with new environmental regulations through the ECRC (see the Environmental Compliance and Regulation sections).

We periodically assess the probability of recovery of the regulatory assets by considering factors such as regulatory environment changes, recent rate orders to other regulated entities in the same jurisdiction, the current political climate in

 

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the state, and the status of any pending or potential deregulation legislation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. We believe the application of regulatory accounting guidance is a critical accounting policy since a change in these assumptions may result in a material impact on reported assets and the results of operations (see the Regulation section and Notes 1 and 3 to the TECO Energy Consolidated Financial Statements).

RECENTLY ISSUED ACCOUNTING STANDARDS

Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses

In July 2010, the Financial Accounting Standards Board (FASB) issued guidance requiring improved disclosures about the credit quality of a company’s financing receivables and their associated credit reserves. The guidance is effective for interim and annual periods that end after Dec. 15, 2010. This guidance did not have any effect on the company’s results of operations, statement of position or cash flows.

Subsequent Events

In February 2010, the FASB issued additional guidance related to subsequent event disclosure. The guidance was effective upon issuance and has no effect on the company’s results of operations, statement of position or cash flows.

Fair Value Measures and Disclosures

In January 2010, the FASB issued guidance that requires entities to disclose more information regarding the movements between Levels 1 and 2 of the fair value hierarchy. The guidance was effective for fiscal years that begin after Dec. 15, 2010, and for interim periods within that year. This guidance will not have any effect on the company’s results of operations, statement of position or cash flows.

INFLATION

The effects of general inflation on our results have not been significant for the past several years. The annual average rate of inflation, as measured by the Consumer Price Index (CPI-U), all items, all urban consumers, as reported by the U.S. Department of Labor, was 1.5%, 2.7% and 3.8% in 2010, 2009 and 2008, respectively. The current economic situation and the state of the economic recovery cause the outlook for 2011 to be stronger than 2010. Reports published by the Federal Reserve Bank of Atlanta indicate that CPI-U is expected to rise 1.7% in 2011.

ENVIRONMENTAL COMPLIANCE

Environmental Matters

Among our companies, Tampa Electric has the most significant number of stationary sources with air emissions regulated by the Clean Air Act, material Clean Water Act implications, and that may be impacted by possible federal and state legislative initiatives. Tampa Electric has undertaken major steps to dramatically reduce its air emissions through a series of voluntary actions, including technology selection (e.g., IGCC and conversion of coal-fired units to natural-gas fired combined cycle); implementation of a responsible fuel mix taking into account price and reliability impacts to its customers; a substantial capital expenditure program to add Best Available Control Technology (BACT) emissions controls; implementation of additional controls to accomplish early reductions of certain emissions; and enhanced controls and monitoring systems for certain pollutants. Together, these improvements represent an investment in excess of $2 billion since 1994.

Through these actions, Tampa Electric has achieved significant reductions of all air pollutants, including CO2, while maintaining a reasonable fuel mix through the clean use of coal for the economic benefit of its customers.

Air Quality Control

Consent Decree

Tampa Electric, through voluntary negotiations with the U.S. Environmental Protection Agency (EPA), the U.S. Department of Justice (DOJ) and the Florida Department of Environmental Protection (FDEP), signed a Consent Decree, which became effective Feb. 29, 2000, and a Consent Final Judgment, which became effective Dec. 6, 1999, as settlement of federal and state litigation. Pursuant to these agreements, allegations of violations of New Source Review requirements of the Clean Air Act were resolved, a provision was made for environmental controls and pollution reductions, and Tampa Electric implemented a comprehensive program to dramatically decrease emissions from its power plants.

The emission reduction requirements included specific detail with respect to the availability of flue gas desulfurization

 

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systems (scrubbers) to help reduce SO2, projects for NOx reduction on Big Bend Units 1 through 4, and the repowering of the coal-fired Gannon Power Station to natural gas, which was renamed as the H. L. Culbreath Bayside Power Station (Bayside Power Station), in 2003 and 2004. Upon completion of the conversion, the station capacity was approximately 1,800 megawatts (nominal) of natural gas-fueled, combined-cycle electric generation. The repowering has reduced the facility’s NOx and SO2 emissions by approximately 99% and particulate matter (PM) emissions by approximately 92% from 1998 levels.

In 2004, Tampa Electric made its NOx reduction technology selection and decided to install SCR systems for NOx control on the four coal-fired Big Bend units. The units were reported in-service in May 2007, June 2008, May 2009 and May 2010.

The FPSC has determined that it is appropriate for Tampa Electric to recover the operating costs of and earn a return on the investment in the SCRs to be installed on all four of the units at the Big Bend Power Station and pre-SCR projects on Big Bend Units 1–3 (which are early plant improvements to reduce NOx emissions prior to installing the SCRs) through the Environmental Cost Recovery Clause (ECRC see the Regulation section). Cost recovery for the SCRs began for each unit in the year that the unit entered service.

In November 2007, Tampa Electric entered into an agreement with the EPA and DOJ for a Second Amendment to the Consent Decree. The Second Amendment: 1) establishes a 0.12 lb/MMBtu NOx limit on a 30-day rolling average for Big Bend Units 1 through 3, which is lower than the original Consent Decree, which had a provision for a limit as high as 0.15 lb/MMBtu depending on certain conditions; 2) allows for the sale of NOx allowances gained as a result of surpassing the emission limit goals of the Consent Decree; and 3) calls for Tampa Electric to install a second PM Continuous Emissions Monitoring System and potentially replace the originally installed system if the new system is successful.

Emission Reductions

Projects committed to under the Consent Decree and Consent Final Judgment have resulted in significant reductions in emissions. Since 1998, Tampa Electric has reduced annual SO2, NOx and PM emissions from its facilities by 164,000 tons, 63,000 tons and 4,500 tons, respectively.

Reductions in SO2 emissions were accomplished through the installation of scrubber systems on Big Bend Units 1 and 2 in 1999. Big Bend Unit 4 was originally constructed with a scrubber. The Big Bend Unit 4 scrubber system was modified in 1994 to allow it to scrub emissions from Big Bend Unit 3 as well. Currently the scrubbers at the Big Bend Power Station are capable of removing more than 95% of the SO2 emissions from the flue gas streams.

The repowering of the Gannon Power Station to the Bayside Power Station has resulted in a significant reduction in emissions of all pollutant types. With the completion of the final Big Bend SCR in May 2010, the SCR projects resulted in a total phased reduction of NOx emissions by 63,000 tons per year from 1998 levels.

In total, Tampa Electric’s emission reduction initiatives have resulted in the annual reduction of SO2, NOx and PM emissions by 94%, 91% and 87% in 2010, respectively, below 1998 levels. With these state-of-the-art improvements in place, Tampa Electric’s activities have helped to significantly enhance the quality of the air in the community. As a result of all its completed emission reduction actions, Tampa Electric has achieved emission reduction levels called for in Phase I of the Clean Air Interstate Rule (CAIR). In July 2008, U.S. Court of Appeals for the District of Columbia Circuit vacated CAIR on emissions of SO2 and NOx. The federal appeals court reinstated CAIR in December 2008 as an interim solution.

On Sep. 16, 2009, the EPA announced it would reconsider its 2008 decision setting national standards for ground-level ozone. The EPA is reconsidering the standards to ensure they are grounded in science, protect public health with an adequate margin of safety, and are sufficient to protect the environment. Much of the State of Florida is not expected to meet the current ground-level ozone standards and will most likely be deemed non-attainment. A non-attainment area is an area that does not meet National Ambient Air Quality Standards under the Clean Air Act. States not in compliance will establish State Implementation Plans (SIP). Compliance with a Florida SIP may be accomplished by utilizing existing controls to a greater extent or installing new control technology to make further reductions. Future power generation expansion in a non-attainment classification would require purchasing emissions offsets or making reductions in existing Tampa Electric facilities to generate offsets.

In July 2010, the EPA proposed a new rule, Clean Air Transport Rule (CATR) to replace CAIR. CATR is focused on reducing SO2 and NOX in 31 eastern states and the District of Columbia. Compliance with CATR, which would be measured at the individual power plant level, would most likely require the additions of scrubbers or SCRs on coal-fired power plants. In addition, the rule proposes intrastate emissions allowance trading and limited interstate emissions allowance trading to achieve compliance. The final rules are expected in 2011 with implementation in the 2012 to 2014 time frame. It is likely that the EPA will propose new ozone and particulate rules and would incorporate them into CATR. All of Tampa Electric’s conventional coal fired units are already equipped with scrubbers and SCRs, and the Polk Unit 1 IGCC unit removes SO2 in the gasification process.

The EPA is under a court order to issue rules in March 2011 to reduce Hazardous Air Pollutants (HAPS). These rules are expected to reduce mercury, acid gas, organics, and heavy metals emissions and require Maximum Achievable Control Technology (MACT). The final HAPS MACT rules are expected in late 2011 with implementation in 2014 or 2015. A

 

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potential outcome of the HAPS MACT rule is the retirement of smaller, older coal-fired power plants that do not already have emissions controls installed. All of Tampa Electric’s conventional coal fired units are already equipped with scrubbers and SCRs, and the Polk Unit 1 IGCC unit emissions are minimized in the gasification process, therefore Tampa Electric expects the co-benefits of these control devices to minimize the impact of this rule.

Reductions in mercury emissions have occurred due to the repowering of the Gannon Power Station to the Bayside Power Station. At the Bayside Power Station, where mercury levels have decreased 99% below 1998 levels, there are virtually zero mercury emissions. Additional mercury reductions have been achieved from the installation of NOx controls at Big Bend Power Station, which have led to a reduction of mercury emissions of more than 75% from 1998 levels. The Clean Air Mercury Rule (CAMR) Phase I requirements were scheduled for implementation in 2010. CAMR was vacated by the U.S. Court of Appeals for the District of Columbia Circuit on Feb. 8, 2008. Prior to the court’s decision Tampa Electric expected that it would have been in compliance with CAMR Phase I without additional capital investment.

Carbon Reductions

Tampa Electric has historically supported voluntary efforts to reduce carbon emissions and has taken significant steps to reduce overall emissions at Tampa Electric’s facilities. Since 1998, Tampa Electric has reduced its system-wide emissions of CO2 by approximately 20%, bringing emissions to near 1990 levels. Tampa Electric expects emissions of CO2 to remain near 1990 levels until the addition of the next baseload unit, which is not expected until after 2014 (see the Tampa Electric and Capital Expenditures sections). Tampa Electric estimates that the repowering to natural gas and the shut-down of the Gannon Station coal-fired units resulted in an annual decrease in CO2 emissions of approximately 4.8 million tons below 1998 levels. During this same time frame, the numbers of retail customers and retail energy sales have risen by approximately 25%.

Tampa Electric’s voluntary activities to reduce carbon emissions also include membership in the U.S. Department of Energy’s Climate Challenge (now Power Partners) program since 1994, voluntary annual reporting of greenhouse gas (GHG) emissions through the Energy Information Agency (EIA) EIA-1605(b) Report beginning in 1995 and participation in the Chicago Climate Exchange (CCX), a voluntary but legally binding cap and trade program dedicated to reducing GHG emissions since 2003. Because of Tampa Electric’s membership in the CCX, its reported CO2 emissions are audited annually by the Financial Industry Regulatory Authority (formerly National Association of Securities Dealers), which has certified the results thus far. In January 2008, the CCX recognized Tampa Electric for achieving its Phase I GHG participation targets for CO2 reduction. While the commitment required in Phase I was a reduction of 4% below the average of the year 1998 – 2001, Tampa Electric surpassed this level with an actual reduction of approximately 20%.

Recently the EPA issued its Final Rule on the mandatory reporting of GHGs, requiring facilities that emit 25,000 metric tons or more of CO2 per year to begin collecting GHG data under a new reporting system on Jan. 1, 2010, with the first annual report due Mar. 31, 2011. Tampa Electric expects to comply with the mandatory reporting requirement, in large part utilizing the same methods and procedures utilized for the voluntary activities.

Climate Change

There are pending legislative and regulatory initiatives on the federal and state levels to establish programs that would require reductions in GHG emissions. While the timing of passage of any federal legislation into law remains uncertain, we will participate in the debate in an effort to encourage a comprehensive environmental approach to carbon emission reductions that maintains a reliable energy supply at affordable prices. In order to meet the reduction contemplated, Tampa Electric could be required to make significant additional capital investments in technologies to reduce GHG that are not yet commercially viable.

On Dec. 15, 2009, the EPA published the final Endangerment Finding in the Federal Register. Although the finding is technically being made in the context of GHG emissions from new motor vehicles and does not in itself impose any requirements on industry or other entities, the finding will trigger GHG regulation of a variety of sources under the CAA. Related to utility sources, the EPA’s “tailoring rule” rule, which addresses the GHG emission threshold triggers that would require permitting review of new and/or major modifications to existing stationary sources of GHG emissions, became effective Jan. 2, 2011. While this rule does not have an immediate impact on Tampa Electric’s on-going operations, it will factor into any permitting activities for new and modified fossil-fuel fired electric generating units going forward.

At the state level, activities aimed at reducing Florida’s GHG emissions were initiated through the former Governor’s Executive Orders in 2007 and broad energy and climate legislation was passed by the state legislature. However, the process has since slowed and is likely to be pushed out since the issue has become increasingly active at the federal level.

The company is examining various options relating to its carbon emissions. At this time, Tampa Electric expects to meet its needs for its next baseload generating capacity with natural gas fired combined-cycle technology, as well as energy efficiency programs and renewable resources (see the Tampa Electric section). While natural gas has lower carbon emissions than coal, fuel price changes have the potential to make natural gas generating facilities less economic than coal-fired facilities. Large-scale fuel switching from coal to natural gas by utilities could increase natural gas prices,

 

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which would reduce the economic efficiency of natural gas generation facilities. Increased costs for electricity may cause customers to change usage patterns, which would impact Tampa Electric’s sales.

Tampa Electric currently emits approximately 16.6 million tons of CO2 per year. Assuming a projected long-term average annual load growth of 1.0% - 2.0%, Tampa Electric may emit approximately 19.8 million tons of CO2 (an increase of approximately 19%) by 2020 if natural gas-fired peaking and combined-cycle generation additions are used to meet growing customer needs.

Tampa Electric expects that the costs to comply with new environmental regulations would be eligible for recovery through the ECRC. If approved as prudent, the costs required to comply with CO2 emissions reductions would be reflected in customers’ bills. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, Tampa Electric could seek to recover those costs through a base-rate proceeding, but can not predict whether the FPSC would grant such recovery. Although Tampa Electric’s current coal-based generation has declined to less than 60% of its output in 2010 from 95% of its output in 2002, due primarily to the conversion of the coal-fired Gannon Power Station into the natural gas-fired Bayside Power Station, coal fired facilities remain a significant part of Tampa Electric’s generation fleet and additional coal units could be used in the future.

In the case of TECO Guatemala, the coal-fired San José Power Station in Guatemala is in compliance with current World Bank and Guatemalan Environmental Guidelines. While there are no known plans for legislation mandating GHG reductions in Guatemala, new rules or regulations could require additional capital investments or increase operating costs.

In the case of TECO Coal, it is unclear if the requirements for GHG emissions reductions would directly impact it as a carbon-based fuel provider or the user. In either case, these requirements could make the use of coal more expensive or less desirable, which could impact TECO Coal’s margins and profitability.

Renewable Energy

Renewables are a component of Tampa Electric’s environmental portfolio. Tampa Electric’s renewable energy program offers to sell renewable energy as an option to customers and utilizes energy generated in the state from renewable sources (e.g. biomass and solar). To date, 39 million kWh of renewable energy have been produced to support participating customer requirements.

Tampa Electric has installed 81.7 kilowatts of solar panels to generate electricity from the sun at two schools, Tampa Electric’s Manatee Viewing Center, the Museum of Science and Industry, Tampa’s Lowry Park Zoo and the Florida Aquarium, and continues to evaluate opportunities for additional solar panel installations. Tampa Electric’s largest solar panel array, rated at 23.8 kilowatts, is located at Tampa Electric’s Manatee Viewing Center in Apollo Beach, Florida. The electricity the photovoltaic array generates, which flows to Tampa Electric’s grid, could offset the carbon dioxide emissions produced by four typical-size cars in a year. The company continues to evaluate opportunities for additional solar panel installations. In the area of biomass, which is organic plant material from yard clippings and other vegetation, Tampa Electric has tested bahia grass as a fuel to generate electricity at the Polk Power Station, where it was ground and mixed with the pulverized coal slurry used in the plant’s gasifier.

Despite the emphasis on the use of renewable energy sources, an FPSC study conducted by Navigant Consulting in 2008 indicates that only under the most favorable conditions of high customer incentives, a mature Renewable Energy Credit (REC) market and a high revenue rate cap would allow utilities to achieve the former Governor’s renewable energy target. The Navigant study also found that solar photovoltaic power generation and biomass were the most viable sources of renewable energy and that Florida was a poor location for either significant land based wind generation or concentrating solar generation. While support for tax incentives for renewable energy development specific to regional disparities may facilitate the development of new sources, mandates for renewable portfolios at high percentages create concerns that RECs will have to be purchased to meet the mandate, rates for customers will grow rapidly and such mandates are not likely to result in significant quantities of renewable energy sources to be developed in the state. A mandatory renewable energy portfolio standard could add to Tampa Electric’s costs and adversely affect its operating results.

In Florida, the Executive Orders tasked the FPSC with evaluating a renewable portfolio target of 20% by 2020. The 2008 Energy Bill directed the FPSC to draft a rule for a RPS to be presented to the Florida Legislature for ratification, but did not specify targets and timeframes. Under this direction, the FPSC submitted recommendations for ratification, but ultimately the Legislature did not ratify the rule in the 2009 session and is not expected to do so going forward. While renewable energy issues remain a part of the discussion in Florida, and many groups are emphasizing the need for renewable energy legislation, the Legislature may take up the issue of renewables in the upcoming legislative session in 2011, but prospects are uncertain.

Although the U.S. Congress has considered, but to date has not passed, a federal RPS, there is likely to be an increased emphasis on the passage of a federal RPS. Tampa Electric could incur significant costs to comply with a high percentage renewable energy portfolio standard, as proposed, and its operating results could be adversely affected if the company were not permitted to recover these costs from customers, or if customers change usage patterns in response to increased

 

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rates.

Water Supply and Quality

The EPA’s final Clean Water Act Section 316(b) rule became effective Jul. 9, 2004. The rule established aquatic protection requirements for existing facilities that withdraw 50 million gallons or more of water per day from rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes. Tampa Electric uses water from Tampa Bay at its Bayside and Big Bend facilities as cooling water. Both plants use mesh screens to reduce the adverse impacts to aquatic organisms and Big Bend units 3 and 4 use proprietary fine-mesh screens, the best available technology, to further reduce impacts to aquatic organisms. Subsequent to promulgation of the rule, a number of states, environmental groups and others sought judicial review of the rule. On Jan. 25, 2007, the U.S. Court of Appeals for the Second Circuit overturned and remanded several provisions of the rule to the EPA for revisions. Among other things, the court rejected the EPA’s use of “cost-benefit” analysis and suggested some ways to incorporate cost considerations. The Supreme Court agreed to review the Second Circuit’s decision and heard arguments in December 2008. The EPA decided to rewrite the rule, and expects to propose a new rule in 2011. The full impact of the new regulations will depend on subsequent legal proceedings, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies.

On Dec. 6, 2010, the EPA published its final rule, setting numeric nutrient criteria for Florida’s lakes and flowing waters. The final rule is being challenged in the courts by numerous parties, including the State of Florida. The final rule sets numeric limits for nitrogen and phosphorous in lakes and streams and for nitrate plus nitrite in springs. The EPA promulgated the rule pursuant to the terms of a consent decree approved by the court in Florida Wildlife Federation v. Jackson, 08-0324 (N.D. Fla.), in which environmentalists sued the Agency for allegedly violating a duty under the Federal Water Pollution Control Act (Clean Water Act or Act) to set the numeric criteria. In response to comments raising numerous implementation concerns, the EPA decided to delay the effective date of the criteria until 15 months after publication. The EPA announced that, in the interim, it will undertake a series of implementation steps in Florida, including an “education and outreach rollout,” training meetings, and the development of guidance materials to coincide with the expected comment period on proposed site-specific alternative criteria. If the rule is implemented as adopted, it would directly affect Polk Power Station’s cooling reservoir discharge to surface water, requiring the station to reduce the amount of nutrients in the cooling reservoir water before discharge. However, the full effect of the EPA’s numeric nutrient criteria will depend on the outcome of the various legal proceedings. Also pursuant to the aforementioned consent decree, the EPA will propose numeric criteria for estuaries and coastal waters by November 2011, and finalize the rules by August 2012 pending the outcome of the previously described legal challenges.

The Big Bend, Bayside and Polk Power stations also use water on a daily basis to generate electricity with steam and to operate emission control devices (e.g. its scrubbers to reduce SO2 emissions, water injection to reduce NOx emissions). Water recycling and beneficial reuse programs are widely employed in the fresh water systems at all three power stations to reduce demand on higher-cost water sources such as municipal water systems.

In December 2010, Clintwood Elkhorn Mining Company, a subsidiary of TECO Coal, received an Administrative Order from the EPA relating to the discharge of wastewater associated with inactive mining operations in Pike County, Kentucky. TECO Coal is in the process of responding to such matter, and the scope and extent of its potential liability, if any, and the costs of any required investigation and remediation related to its inactive mining operations in the area have not been determined.

Section 404 of the Clean Water Act and Coal Surface Mine Permits

For the past several years, new permits issued by the USACE under Section 404 of the Clean Water Act for new surface coal mining operations have been challenged in court by various environmental groups resulting in a backlog of permit applications and very few permits being issued.

On Apr. 1, 2010, the EPA issued new guidance on environmental permitting requirements for Appalachian mountain top removal and other surface mining projects. The guidance limits conductivity (level of mineral salts) in water discharges into streams from permitted areas, and was effective immediately on an interim basis. The EPA will decide whether to modify the guidance after consideration of public comments and the results of the SAB technical review of the EPA scientific reports, which is expected in April 2011. Because the EPA’s standards appear to be unachievable under most circumstances, surface mining activity could be substantially curtailed since most new and pending permits would likely be rejected. This guidance could also be extended to discharges from deep mines and preparation plants, which could result in a substantial curtailing of those activities as well. This guidance is facing legal challenges from coal mining industry-related organizations and states relating to the stringency of the standards as well as the focus on the coal industry and the Appalachian region in particular.

Conservation

Energy conservation is becoming increasingly important in a period of volatile energy prices and in the GHG emissions reduction debate. In 2007, the Governor signed three Executive Orders aimed at reducing Florida’s emissions of GHG, which included a directive for the development of new policies to enhance energy efficiency and conservation statewide.

 

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The Climate Action Team described above completed a final report by the October 2008 deadline and included policy recommendations on energy efficiency and conservation targets which may either be used in the development of new legislation or in the augmentation of existing FPSC regulation.

During 2010, Tampa Electric offered customers 27 comprehensive programs to conserve energy. These programs were designed to reduce peak energy demand which allows Tampa Electric to delay construction of future generation facilities. Since their inception, these conservation programs have reduced the summer peak demand by 273 megawatts, and the winter peak demand by 687 megawatts. These programs and their costs are approved annually by the FPSC with the costs recovered through a clause on the customer’s bill. In addition, PGS offers programs that enable customers to reduce their energy consumption with the costs also recovered through a clause on the customer’s bill.

In December 2009, the FPSC established new demand-side-management (DSM) goals for 2010-2019 for all investor-owned electric utilities. For Tampa Electric, the summer and winter demand goals are 138 and 109 megawatts, respectively, and the annual energy goal is 360 gigawatt hours. These goals are very aggressive and represent as much as a 300 percent increase over the company’s previous goals.

Tampa Electric developed its DSM plan designed to meet the new goals and filed the plan with the FPSC in March 2010. The plan contained 36 programs that include two offerings promoting the renewable technologies of photovoltaics and solar water heating. Final approval of the plan occurred in November 2010. The company is actively developing the infrastructure necessary to support and promote the new plan and expects to make the programs available to customers during the second quarter of 2011.

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company, through its Tampa Electric and PGS divisions, is a potentially responsible party (PRP) for certain superfund sites and, through its PGS 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, 2010, Tampa Electric Company has estimated its ultimate financial liability to be approximately $21.3 million (primarily related to PGS), and this amount has been reflected in the company’s financial statements. This amount is higher than prior estimates to reflect a 2010 study for the costs of remediation primarily related to one site. 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 amounts represent only the estimated portion of the cleanup costs attributable to Tampa Electric Company. The estimates to perform the work are based on actual estimates obtained from contractors or Tampa Electric Company’s experience with similar work, adjusted for site specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

Allocation of the responsibility for remediation costs among Tampa Electric Company and other PRPs is based on each party’s 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 credit worthy.

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. Under current regulation, these additional costs would be eligible for recovery through customer rates.

In October 2010, the EPA notified Tampa Electric Company that it is a PRP under the federal Superfund law for the proposed contaminated soil removal action and further clean up, if necessary, at a property owned by Tampa Electric Company in Tampa, Florida. The property owned by Tampa Electric Company is undeveloped except for location of transmission lines and poles, and is adjacent to an industrial site, not owned by Tampa Electric Company, which the EPA has studied since 1992 or earlier. The EPA has asserted this potential liability due to Tampa Electric Company’s ownership of the property described above but, to the knowledge of Tampa Electric Company, is not based upon any release of hazardous substances by Tampa Electric Company. Tampa Electric Company is in the process of responding to such matter, and the scope of its potential liability, if any, and the costs of any required investigations and remediation have not been determined.

In 2004 Merco Group at Adventura Landings I, II, and III (together Merco) filed suit against PGS in Dade County Circuit Court alleging that coal tar from a certain former PGS manufactured gas plant site had been deposited in the early 1960s onto property owned by Merco. PGS contends that the coal tar did not originate from is manufactured gas plant site and has filed a third-party complaint against Continental Holdings, Inc. as the owner at the relevant time of the site that PGS believes was the source of the coal tar on Merco’s property. Trial in this matter is scheduled for April 2011. At this time, the ultimate resolution of this proceeding is uncertain and no potential loss has been accrued (see Footnote 12 to the TECO Energy Consolidated Financial Statements).

Coal Combustion Byproducts Recycling

The combustion of coal at two of Tampa Electric’s power generating facilities, the Big Bend and Polk Power stations, produces ash and other byproducts, collectively known as Coal Combustion Byproducts (CCBs). The CCBs produced at Big Bend include fly ash, gypsum, boiler slag, bottom ash and economizer ash. The CCBs produced at the Polk Power Station include gasifier slag and sulfuric acid. Overall, over 97% of all CCBs produced at these facilities were marketed to customers for beneficial use in commercial and industrial products in 2010.

In response to the TVA Kingston coal ash pond failure in December 2008, the EPA proposed new regulations for the

 

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management and disposal of CCBs. These proposed rules include two potential designations of CCBs both of which are intended to eliminate unlined wet impoundments. One designation would categorize CCBs as hazardous wastes. The other proposed rule would set minimum standards for the final disposal of CCBs. In addition, these rules would prohibit construction of new unlined by-product storage ponds and place additional management requirements on existing ash ponds such as those at Big Bend. Only the hazardous designation would be expected to affect Tampa Electric’s current management practices and storage facilities for CCBs. Required changes would include disposing of any CCB waste as Hazardous Waste, converting to dry handling of coal ash, and elimination of any wet storage impoundments in current use. The non-hazardous option would not be expected to have as great an impact on Tampa Electric, since this option would allow for the continued operation of lined wet impoundments and all of its CCB storage areas are either lined or are in the process of being lined in accordance with current requirements.

REGULATION

Tampa Electric’s and PGS’ retail operations are regulated by the 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 provides an opportunity for the utility to collect total revenues (revenue requirements) equal to its cost to provide service, plus a reasonable return on invested capital.

For both Tampa Electric and PGS, the costs of owning, operating and maintaining the utility systems, excluding fuel and conservation costs as well as purchased power and certain environmental costs for the electric system, are recovered through base rates. These costs include operation and maintenance expenses, depreciation and taxes, as well as a return on investment in assets used and useful in providing electric and natural gas distribution services (rate base). The rate of return on rate base, which is intended to approximate the individual company’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 (ROE). Base rates are determined in FPSC revenue requirement and rate setting hearings which occur at irregular intervals at the initiative of Tampa Electric, PGS, the FPSC or other parties.

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 and ancillary services, and accounting practices.

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 the Environmental Compliance section).

Tampa Electric - Base Rates

Tampa Electric’s rates and allowed ROE range of 10.25% to 12.25%, with a midpoint of 11.25%, which was established in 2009, 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’s 13-month average regulatory ROE was 8.7% at the end of 2008 compared to an authorized midpoint of 11.75%, due to lower customer growth, slower energy sales growth, and ongoing high levels of capital investment. As a result, Tampa Electric filed for a $228 million base rate increase in August 2008. In March 2009, the FPSC awarded $104 million