TECO Energy 10-K 2010
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
For the fiscal year ended December 31, 2009
For the transition period from to
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark 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 ¨ 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, 2009 was $2,549,968,020 based on the closing sale price as reported on the New York Stock Exchange.
The aggregate market value of Tampa Electric Companys common stock held by non-affiliates of the registrant as of Jun. 30, 2009 was zero.
The number of shares of TECO Energy, Inc.s common stock outstanding as of Feb. 22, 2010 was 213,857,116. As of Feb. 22, 2010, there were 10 shares of Tampa Electric Companys 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 2010 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 of 183
Index to Exhibits begins on page 180
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 4,073 employees as of Dec. 31, 2009.
TECO Energys Corporate Governance Guidelines, the charter of each committee of the Board of Directors, and the code of ethics applicable to all directors, officers and employees, the Standards of Integrity, are available on the Investors section of TECO Energys 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 Energys 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 Energys business segments, and revenues for those segments for the years indicated, are identified below.
Tampa Electric Company, a Florida corporation and TECO Energys largest subsidiary, has two business segments. Its Tampa Electric division (Tampa Electric) provides retail electric service to almost 667,000 customers in West Central Florida with a net winter system generating capability of 4,719 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 334,000 customers, PGS has operations in Floridas major metropolitan areas. Annual natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) in 2009 was 1.4 billion therms.
TECO Coal Corporation (TECO Coal), a Kentucky corporation, has 13 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 equity investments in unconsolidated subsidiaries that participate in two contracted power plants and an interest in Distribućion Eléctrica Centro Americana II, S.A. (DECA II), which has an ownership interest in Guatemalas largest distribution utility, Empresa Eléctrica de Guatemala, S.A. (EEGSA) and other affiliated energy-related companies.
TECO Transport Corporation (TECO Transport), a Florida corporation, was sold on Dec. 4, 2007. During 2007, it owned no operating assets but owned all of the common stock of, or membership interests in, nine subsidiaries which provided waterborne transportation, storage and transfer services of coal and other dry-bulk commodities.
Revenues from Continuing Operations
For additional financial information regarding TECO Energys 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 of Guatemala subsidiaries.
Discontinued Operations/Asset Dispositions
TECO Energys results for 2007 include amounts related to asset dispositions as part of the companys business strategy to focus on the electric and gas utilities, eliminate exposure to the merchant power sector and retire parent debt.
In the fourth quarter of 2007, TECO Energy completed its sale of TECO Transport to an unaffiliated investment group. As a result of its continuing involvement via a waterborne transportation contract with Tampa Electric, all results through the date of sale were accounted for in continuing operations. In the second quarter of 2007, a favorable conclusion was reached with taxing authorities regarding the 2005 disposition of Union and Gila merchant power plants. This resulted in after-tax net income of $14.3 million reflected in discontinued operations.
TAMPA ELECTRICElectric 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 2,324 employees as of Dec. 31, 2009, of which 898 were represented by the International Brotherhood of Electrical Workers and 209 were represented by the Office and Professional Employees International Union.
In 2009, approximately 49% of Tampa Electrics total operating revenue was derived from residential sales, 31% from commercial sales, 9% from industrial sales and 11% from other sales, including bulk power sales for resale. The sources of operating revenue and megawatt hour sales for the years indicated were as follows:
No significant part of Tampa Electrics 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 Electrics 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.
The retail operations of Tampa Electric are regulated by the Florida Public Service Commission (FPSC), which has jurisdiction over retail rates, quality of service and reliability, issuances of securities, planning, siting and construction of facilities, accounting and depreciation practices and other matters.
In general, the FPSCs pricing objective is to set rates at a level that allows the utility to collect total revenues (revenue requirements) equal to its cost of providing service, plus a reasonable return on invested capital.
The costs of owning, operating and maintaining the utility system, other than fuel, purchased power, conservation and certain environmental costs, are recovered through base rates. These costs include operation and maintenance expenses, depreciation and taxes, as well as a return on Tampa Electrics investment in assets used and useful in providing electric service (rate base). The rate of return on rate base, which is intended to approximate Tampa Electrics weighted cost of capital, primarily includes its costs for debt, deferred income taxes at a zero cost rate and an allowed return on common equity. Base rates are determined in FPSC rate setting hearings which occur at irregular intervals at the initiative of Tampa Electric, the FPSC or other parties.
Tampa Electrics rates and allowed return on equity (ROE) range of 10.25% to 12.25%, with a midpoint of 11.25%, 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. These values were set by the FPSC in March 2009 as part of Tampa Electrics base rate proceeding filed in August 2008.
Prior to August 2008, Tampa Electric had not sought a base rate increase since 1992. As a result of lower customer growth, lower energy sales growth, and ongoing high levels of capital investment, Tampa Electrics 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 2008. The filing included a request for an ROE mid-point of 12%, 54.0% equity in the capital structure and rate base of $3.7 billion. The formal hearing before the FPSC was held in late January 2009 and in March 2009, the FPSC approved a total base rate increase of $137.8 million, $104.3 million effective May 2009 and an additional $33.5 million, subject to audit of actual final cost, actual in service dates, need and prudency, effective January 2010 associated with Tampa Electrics completion of five combustion turbine (CT) generation units and new rail facilities by Dec. 31, 2009. Motions for reconsideration of the FPSCs decision were filed by Tampa Electric (addressing an incorrect tax calculation) and the intervenors (addressing the appropriateness of the additional rate increase in January 2010). In July 2009, the FPSC approved Tampa Electrics motion and denied the intervenors motion for reconsideration, which increased the approved base rate increase to $147.7 million. Due to the FPSCs denial of the intervenors motion for reconsideration, they have notified the FPSC of their intent to file an appeal with the Florida Supreme Court.
In October 2009, Tampa Electric filed its petition supporting the cost and in service operation of the CTs and rail facilities, the continuing need for the CTs and requesting the proposed rates become effective January 2010 as authorized by the FPSC. The FPSC determined, based in part on its staff audit of the actual costs of the CTs, that the January base rate change should be reduced by $8.4 million to $25.7 million, subject to refund. An evidentiary hearing will be held during 2010 regarding the need for the CTs, the appropriate amount to be recovered and the resulting rates. The intervenors appeal to the Florida Supreme Court is independent of the FPSC hearing. The intervenors are expected to file their initial appellate brief with the Florida Supreme Court in February 2010. A decision date in that case is uncertain.
Fuel, purchased power, conservation and certain environmental costs are recovered through levelized monthly charges established pursuant to the FPSCs cost recovery clauses. These charges, which are reset annually in an FPSC proceeding, are based on estimated costs of fuel, environmental compliance, conservation programs, purchased power and estimated customer usage for a specific recovery period, with a true-up adjustment to reflect the variance of actual costs from the projected costs. The FPSC may disallow recovery of any costs that it considers imprudently incurred.
In November 2008, the FPSC approved Tampa Electrics 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 (coincident with the base rate adjustments made as a result of the base rate proceeding). Residential energy rates also reflect a two-block base rate and fuel factor structure with a lower factor for the first 1,000 kilowatt-hours used each month. Tampa Electrics residential customer rate per 1,000 kilowatt-hours decreased $1.94 from $114.67 in August of 2009 to $112.73 in 2010.
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 include the expected cost for natural gas and coal in 2010 as well as the solid fuel transportation costs associated with the companys transportation agreements, 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.
The FPSC determined that 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 cost recovery started in the respective in service years. The SCR for Big Bend Unit 1 is scheduled to enter service by May 1, 2010, and cost recovery for the capital investment and operating costs for that unit has been approved by the FPSC to start in 2010.
Tampa Electric is also subject to regulation by the Federal Energy Regulatory Commission (FERC) in various respects, including wholesale power sales, certain wholesale power purchases, transmission services, bulk electric system reliability standards, affiliate transactions and accounting and depreciation practices. Regarding reliability standards, a spot audit of Tampa Electric was conducted Nov. 9-13, 2009 by the Florida Reliability Coordinating Council (FRCC). FRCC is a Regional Entity operating under a Delegation Agreement approved by the North American Electric Reliability Corporation (NERC) and FERC. The FRCC audit assessed compliance with the NERC Critical Infrastructure Protection (CIP) or cyber standards. The FRCC Compliance Staff concluded that Tampa Electric was fully compliant with 12 of the 13 NERC CIP requirements subject to the spot audit with one relatively minor finding. See also the Regulation section of MD&A.
The Energy Policy Act of 2005 repealed the Public Utility Holding Company Act of 1935 (PUHCA), which established a regulatory regime overseen by the SEC, and replaced it with a new statute focused on increased access to holding-company books and records to assist the FERC and state utility regulators in protecting customers of regulated utilities. On Dec. 8, 2005, the FERC finalized rules to implement the congressional mandated repeal of the PUHCA of 1935 and enactment of the PUHCA of 2005. FERC issued its final rules effective Feb. 8, 2006. Pursuant to this Act, TECO Energy has a single-state waiver regarding FERCs access to its holding-company books and records.
Federal, state and local environmental laws and regulations cover air quality, water quality, land use, power plant, substation and transmission line siting, noise and aesthetics, solid waste and other environmental matters (see Environmental Matters section below).
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 Electrics retail and wholesale customers, respectively.
Tampa Electrics retail electric business is substantially free from direct competition with other electric utilities, municipalities and public agencies. At the present time, the principal form of competition at the retail level consists of self-generation available to larger users of electric energy. Such users may seek to expand their alternatives through various initiatives, including legislative and/or regulatory changes that would permit competition at the retail level. Tampa Electric intends to retain and expand its retail business by managing costs and providing high quality service to retail customers.
Presently there is competition in Floridas wholesale power markets, largely as a result of the Energy Policy Act of 1992 and related federal initiatives. However, the states Power Plant Siting Act, which sets the states 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.
Approximately 55% of Tampa Electrics generation of electricity for 2009 was coal-fired, with natural gas representing approximately 45% 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. Tampa Electrics average delivered fuel cost per million British thermal unit (Btu) and average delivered cost per ton of coal burned, have been as follows:
Tampa Electrics 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, burns a combination of high-sulfur coal, a processed oil by-product known as petroleum coke and CT4 which entered commercial operation in August 2009 burns No. 2 fuel oil and natural gas; Polk Unit 1 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 4.2 million tons of coal and petroleum coke during 2009 and estimates that its combined coal and petroleum coke consumption will be about 4.7 million tons for 2010. During 2009, Tampa Electric purchased approximately 67% of its coal under long-term contracts with four suppliers, and approximately 33% 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 79% of its coal and petroleum coke requirements in 2010 under long-term contracts with four suppliers and the remaining 21% in the spot market.
Tampa Electrics 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 2009, approximately 77% of Tampa Electrics coal supply was deep-mined, approximately 14% was surface-mined and the remaining was petroleum coke. Federal surface-mining laws and regulations have not had any material adverse impact on Tampa Electrics 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, 2009, approximately 48% of Tampa Electrics 850,000 MMBtu gas storage capacity was full. Tampa Electric has contracted for 60% of the expected gas needs for the April 2010 through September 2010 period, 50% for October 2010 and 20% for November 2010 through March 2011. In early March 2010 Tampa Electric expects to issue a 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 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 Electrics 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 Electrics 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. Temple Terrace reserved the right to purchase Tampa Electrics 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 November 2039.
Franchise fees payable by Tampa Electric, which totaled $39.4 million in 2009, 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.
Among our companies, Tampa Electric has a number of significant stationary sources with air emissions impacted by the Clean Air Act and material Clean Water Act implications. Tampa Electric has undertaken major steps to dramatically reduce its air emissions through a series of actions, including technology selection (e.g., Integrated Gasification Combined-Cycle (IGCC) and conversion of coal-fired units to natural-gas fired combined cycle); implementing a responsible fuel mix taking into account price and reliability effects on its customers; a substantial capital expenditure program to add Best Available Control Technology (BACT) emissions controls; implementation of additional controls to accomplish earlier reductions of certain emissions allowing for lower emission rates when BACT was ultimately installed; and enhanced controls and monitoring systems for certain pollutants. All of these improvements represent an investment in excess of $2 billion since 1994.
These actions have allowed Tampa Electric to maintain a diverse fuel supply, essential to power generation reliability and customer economic vitality; while at the same time, achieve significant air pollutant emission reductions, including carbon dioxide.
Tampa Electric, through voluntary negotiations with the Environmental Protection Agency (EPA), the U.S. Department of Justice (DOJ) and the 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, provision was made for environmental controls and pollution reductions, and Tampa Electric began implementing 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 the H. L. Culbreath Bayside Power Station (Bayside Power Station), in 2003 and 2004. Upon completion of the conversion, the station capacity was about 1,800 megawatts (nominal) of natural gas-fueled, combined-cycle electric generation. The repowering has reduced the facilitys NOx and SO 2 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 NO x control on the coal-fired Big Bend units. The first three units at Big Bend Power Station were reported in service in May 2007, June 2008 and May 2009, respectively. The remaining unit, Big Bend Unit 1, is expected to be in service in May 2010. Tampa Electrics capital investment forecast includes amounts in 2010 for completion of the final NOx control project (see the Capital Expenditures section).
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 13 (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 in each of the years that the units entered service, Big Bend Unit 4 in 2007, Big Bend Unit 3 in 2008 and Big Bend Unit 2 in 2009. In November 2009, the FPSC approved cost recovery for the capital investment on the Big Bend Unit 1 SCR to start in 2010.
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) 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.
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 154,000 tons, 57,000 tons, and 4,000 tons, respectively.
Reductions in SO2 emissions were accomplished through the installation of scrubber systems on Big Bend Units 1 and 2 in 1999. Big Bend Unit 4 was originally constructed with a scrubber. The Big Bend Unit 4 scrubber system was modified in 1994 to allow it to scrub emissions from Big Bend Unit 3 as well. Currently the scrubbers at Big Bend Power Station remove more than 95% of the SO2 emissions from the flue gas streams.
The repowering of the Gannon Station to the Bayside Power Station has resulted in a significant reduction in emissions of all pollutant types. We expect that Tampa Electrics actions to install NOx emissions controls on all Big Bend units will result in the further reduction of emissions and that by the expected completion of the final unit in 2010, the SCR projects will result in a total phased reduction of NOx by 62,000 tons per year from 1998 levels.
In total, we expect that Tampa Electrics emission reduction initiatives will result in the annual reduction of SO2, NOx and PM emissions by 88%, 90% and 71%, respectively, below 1998 levels by 2010. With these state-of-the-art improvements in place, Tampa Electrics activities have helped to significantly enhance the quality of the air in the community. As a result of already completed emission reduction actions, Tampa Electric has achieved the 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. The EPA is continuing to work on a replacement rule that is expected to be proposed in 2010 and finalized in 2011. Until a new rule is proposed CAIR will remain intact.
A pollution control benefit from the environmental initiatives taken by Tampa Electric is the significant reduction of mercury emissions. At Bayside Power Station, mercury emissions have decreased by 99% from 1998 levels, essentially resulting in zero mercury emissions. Additional mercury reductions come from the installation of NOx controls at Big Bend Power Station, which are expected to lead to a reduction of mercury emissions of more than 75% from 1998 levels by 2010. 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 courts decision Tampa Electric expected that it would have been in compliance with CAMR Phase I without additional capital investment. The EPA is expected to propose new or modified rules to address mercury and other hazardous air pollutants by late 2011.
In 2007 the EPA modified the 24-hour coarse and fine PM ambient air standards. Based on the reduced emissions of PM, sulfates and nitrates resulting from projects associated with compliance with the Consent Decree, as well as local ambient air quality data, the Tampa Electric service area is expected to be in compliance with the proposed new PM standards without additional expenditures by Tampa Electric. (See the Environmental Compliance section of MD&A.)
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 Tampa Electrics service territory is not expected to meet the current ground-level ozone standards and will most likely be deemed non-attainment.
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, 2009, Tampa Electric Company has estimated its ultimate financial liability to be approximately $19.9 million (primarily related to PGS), and this amount has been reflected in the companys financial statements. This amount is higher than prior estimates to reflect a 2009 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 Companys 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 partys relative ownership interest in or usage of a site. Accordingly, Tampa Electric Companys 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.
Tampa Electrics 2009 capital expenditures included $53 million for the installation of SCR equipment at the coal-fired Big Bend Power Station, and $4 million for other environmental compliance projects.
PEOPLES GAS SYSTEMGas 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 334,000 customers. The system includes approximately 11,000 miles of mains and 6,500 miles of service lines. (See PGS Franchises section below.)
In 2009, the total throughput for PGS was 1.4 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 50% of PGS annual therm volume, commercial customers used approximately 26%, and the balance was consumed by residential customers.
While the residential market represents only a small percentage of total therm volume, residential operations comprised almost 31% of total revenues.
Natural gas has historically been used in many traditional industrial and commercial operations throughout Florida, including production of products such as steel, glass, ceramic tile and food products. Within the PGS operating territory, large cogeneration facilities utilize gas-fired technology in the production of electric power and steam.
Revenues and therms for PGS for the years ended Dec. 31, are as follows:
PGS had 520 employees as of Dec. 31, 2009. A total of 79 employees in six of PGS 14 operating divisions are represented by various union organizations.
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 allows a utility such as PGS to collect total revenues (revenue requirements) equal to its cost of providing service, plus a reasonable return on invested capital.
The basic costs of providing natural gas service, other than the costs of purchased gas and interstate pipeline capacity, are recovered through base rates. Base rates are designed to recover the costs of owning, operating and maintaining the utility system. The rate of return on rate base, which is intended to approximate PGS weighted cost of capital, primarily includes its cost for debt, deferred income taxes at a zero cost rate, and an allowed return on common equity. Base rates are determined in FPSC proceedings which occur at irregular intervals at the initiative of PGS, the FPSC or other parties. For a description of recent proceeding activity, see the RegulationPGS 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.
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 pipeline capacity, and estimated customer usage for a specific recovery period, with a true-up adjustment to reflect the variance of actual costs and usage from the projected charges for prior periods. In November 2009, the FPSC approved rates under PGS PGA for the period January 2010 through December 2010 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 its costs incurred in developing and implementing energy conservation programs, which are mandated by Florida law and approved and supervised by the FPSC. PGS is permitted to recover, on a dollar-for-dollar basis, prudently incurred expenditures made in connection with these programs if it demonstrates that the programs are cost effective for its ratepayers. The FPSC requires natural gas utilities to offer transportation-only service to all non-residential customers.
In addition to economic regulation, PGS is subject to the FPSCs 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.
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 all eligible customers and allowing non-residential 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 15,250 transportation-only customers as of Dec. 31, 2009 out of approximately 31,400 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.
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 59 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 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.
PGS holds franchise and other rights with approximately 100 municipalities throughout Florida. These franchises give PGS a right to occupy municipal rights-of-way within the franchise area. The franchises are irrevocable and are not subject to amendment without the consent of PGS, although in certain events, they are subject to forfeiture.
Municipalities are prohibited from granting any franchise for a term exceeding 30 years. Several franchises contain purchase options with respect to the purchase of PGS property located in the franchise area, if the franchise is not renewed; otherwise, based on judicial precedent, PGS is able to keep its facilities in place subject to reasonable rules and regulations imposed by the municipalities.
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 2010, the majority of which will be renewals of existing agreements. Franchise fees payable by PGS, which totaled $9.5 million in 2009, 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.
PGS operations are subject to federal, state and local statutes, rules and regulations relating to the discharge of materials into the environment and the protection of the environment generally that require monitoring, permitting and ongoing expenditures.
Tampa Electric Company is one of several potentially responsible parties for certain superfund sites and, through PGS, for former manufactured gas plant sites. See the previous discussion in the Environmental Matters section of Tampa ElectricElectric Operations.
During the year ended Dec. 31, 2009, PGS did not incur any material capital expenditures to meet environmental requirements, nor are any anticipated for 2010 through 2014.
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, Bear Branch Coal Company, and all of the membership interests in TECO Synfuel Administration, LLC and TECO Synfuel Operations, LLC. The TECO Coal subsidiaries 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 subsidiaries currently operate 27 underground mines, which employ the room and pillar mining method, and 13 surface mines. In 2009, TECO Coal subsidiaries sold 8.75 million tons of coal. None of this coal was sold to Tampa Electric. For the reporting period, the TECO Coal operating companies had a combined estimated 262.2 million tons of proven and probable recoverable reserves.
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.
1988 saw a marketing change in which Gatliff Coal Company began selling ferro-silicon and silicon grade products. 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.
TECO Synfuel Holdings, LLC and TECO Synfuel Administration, LLC were formed in 2003 to administer the production and sale of synfuel product at various TECO Coal subsidiaries. Synfuel operations were terminated at the end of 2007 when the tax credit associated with production of non-conventional fuels expired by statute.
In 2004, the acquisition of properties and the Millard Preparation Facilities (currently idle) from American Electric Power and Kentucky Coal, LLC was completed. The property and facility are located in Pike County, Kentucky.
TECO Coal currently has three 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 Elkhorns Millard Plant is currently idle. 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 15 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 Coals mining complexes to customers by means of railroad cars, trucks, barges or vessels, with rail shipments representing approximately 93.2% of 2009 coal shipments. The map below shows the locations of the three mining complexes and TECO Coals offices in Corbin, Kentucky.
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 Clintwood facilities are located at Biggs, Kentucky, Hurley, Virginia and the Millard facility, which is presently idle, located at Millard, Kentucky. 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
Significant projects for 2009 included the following:
Perry County Coal
Premier Elkhorn Coal
Clintwood Elkhorn Mining
Table 2 below shows annual production for each mining complex for each of the last three years.
D/LDozers and Front-End Loaders
R/BRail to Barge
R/VRail to Ocean Vessel
T/BTruck to Barge
Gatliff Coal Company
Gatliff Coal Company discontinued surface mine operations in the late autumn of 2009. Poor market conditions and a depletion of the low sulfur content coal that was previously required on its sales contract led to this cessation of mining operations. Gatliff Coal Company produced 0.16 million tons of coal in 2009, 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 Companys Tennessee production, which 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 14 underground mines and two surface mines. 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 two 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 idle. In total, Clintwood Elkhorn Mining Company produced 2.02 million tons of coal in 2009, leaving a reserve base of 50.0 million recoverable tons.
Premier Elkhorn Coal Company
Located near Myra, in Pike County, Kentucky, Premier Elkhorn Coal Company is supplied by production from eight underground mines and eight surface mines. Principal products include high-quality steam coal for utilities, specialty stoker products for ferro-silicon and industrial customers, 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 3.22 million tons of coal in 2009 leaving a reserve base of 72.8 million recoverable tons.
Perry County Coal Corporation
Located near Hazard, Kentucky in Perry County, Perry County Coal Corporation is supplied by three underground mines and one surface mine. 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 completed a comparable trade of underground reserves with another mining company of 16.0 million tons. During 2010 this boundary of reserves will continue to be core drilled to confirm final reserve quantities and qualities and to finalize a comprehensive mining plan. Perry County Coal Corporation produced 3.09 million tons of coal in 2009. A baseline review of reserves for Perry County Coal Corporation proved an additional 4.2 million tons of reserves which were previously unreported leaving a reserve base of 136.0 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 subsidiaries sell coal under long-term agreements, which are generally classified as greater than 12 months, and on a spot basis, which is generally classified 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.
TECO Coal subsidiaries transport coal from their mining complexes to customers by rail, barge, vessel and trucks. They employ transportation specialists who coordinate the development of acceptable shipping schedules with its customers, transportation providers and mining facilities.
Primary competitors of TECO Coals subsidiaries are other coal suppliers, many of which are located in Central Appalachia. Even though consolidation and bankruptcy have decreased the number of coal suppliers, the industry is still intensely competitive. To date, the TECO Coal subsidiaries have 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.
As of Dec. 31, 2009, TECO Coal and its subsidiaries employed a total of 1,089 employees.
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 new Miner Act of 2006. TECO Coals 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 claimants treating physician, limited a coal operators ability to introduce medical evidence, and redefined Coal Workers Pneumoconiosis to include chronic obstructive pulmonary disease. These changes in the regulations increased 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.
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.
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 Coals subsidiaries are subject to various federal, state and local air and water pollution standards. In 2009, TECO Coal spent approximately $3.7 million on environmental protection and reclamation programs. TECO Coal expects to spend a similar amount in 2010 on these programs.
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 EPAs 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.
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.
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 coals 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 Coals Central Appalachian reserves are of low sulfur grades.
Surface mine. A mine in which the coal lies near the surface and can be extracted by removing overburden.
Synthetic fuel (Synfuel). A solid fuel that is produced by mixing coal and/or coal waste with various additives, causing a chemical change to occur within the original product.
Tipple. A structure that facilitates the loading of coal into rail cars.
Tons. A short or net ton is equal to 2,000 pounds. A long or British ton is 2,240 pounds; a metric ton is approximately 2,205 pounds. The short ton is the unit of measure referred to in this Form 10-K.
Unassigned reserves. Coal 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 earths surface, an underground mines 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, Inc., has subsidiaries that have interests in independent power projects in Guatemala and a minority ownership interest in an electrical distribution utility and affiliated entities. The TECO Guatemala subsidiaries had 124 employees as of Dec. 31, 2009.
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 for a 15-year period ending in 2010. In 2001, TCAE signed an option with EEGSA to extend that PPA for five years at the end of its current term for approximately $2.9 million. EEGSA is responsible for providing the fuel for the plant, with a subsidiary of TECO Guatemala providing assistance in fuel administration.
In 1998, DECA II, a consortium whose members include 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. TECO Guatemala contributed $100 million in equity and owns a 30% interest in this consortium. At this time, the consortium maintains a controlling interest in EEGSA and other affiliate companies which provide, among other things, electricity transmission services and power sales to large electric customers and engineering services. EEGSA serves more than 900,000 customers in and around the metropolitan area of Guatemala City.
For CGESJ, TCAE and DECA II, TECO Guatemala has obtained political risk insurance for currency inconvertibility, expropriation and political violence covering TECO Guatemalas 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.
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 Electrics 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 to improve, or additional deterioration in the overall economic situation and the currently depressed Florida housing markets, could adversely affect Tampa Electrics 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 regulations or the regulatory environment could reduce revenues or increase costs of competition.
Tampa Electric and PGS operate in highly regulated industries. Their retail operations, including the prices charged, are regulated by the FPSC, and Tampa Electrics 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 Electrics or PGS financial performance by, for example, reducing revenues, increasing competition or costs, threatening investment recovery or impacting rate structure.
Tampa Electric and PGS were awarded ROE ranges with mid-points of 11.25% and 10.75%, respectively in 2009 by the FPSC. In 2010, the FPSC awarded ROE ranges with mid-points of 10.5% and 10.0% to other investor owned utilities in Florida. Our financial results could be adversely affected if the FPSC were to lower the allowed ROE in the next base rate proceedings by either company.
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 ROEs below those levels, which could be, in part, an effort to minimize the impact of utility price changes on customers in the current weak Florida economy. While the FPSC has a history of constructive regulation, the recent actions taken with other companies may signal a change in the Florida regulatory climate. 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 could add to Tampa Electrics 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 coal combustion by-product handling, storage and disposal. As of February 2010, the proposed new rules had not been published. If the new rules reduce or eliminate the beneficial use of coal combustion by-products, or eliminate the use of ponds for by-product storage, it could increase Tampa Electrics operating costs through higher disposal costs.
Federal or state regulation of 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 Electrics 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, but increased costs for electricity may cause customers to change usage patterns, which would impact Tampa Electrics sales. 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 we cannot predict whether the FPSC would grant such recovery.
Changes in environmental laws or regulations could affect TECO Coals customers and could reduce the demand for coal as a fuel source and cause sales to decline.
The operations of TECO Coal and its customers are subject to extensive environmental laws and regulations especially air emissions and air quality standards. In particular, the Clean Air Act and state and local laws and regulations limit emissions of sulfur dioxide, nitrogen oxides, particulate matter and other compounds from electric power plants, which are the single largest users of our coal.
A major by-product of the combustion of coal is carbon dioxide, which is considered a major source of greenhouse gases. Future regulation of greenhouse gases as proposed by various federal, state and international initiatives could cause coal-fired power plants or other industrial users of coal to install expensive or unproven control technologies, cause them to switch to less carbon intensive fuels or shut-down. Any reduction in demand for coal as a fuel source could have a material adverse impact on TECO Coals and our financial results.
The significant, phased reductions in GHG emissions called for by the executive orders signed by the governor of Florida in 2007 could add to Tampa Electrics costs and adversely affect its operating results.
The Governor of Florida signed three Executive Orders in July 2007 aimed at reducing Floridas 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; and the creation of the Governors Action Team on Energy and Climate Change to develop a plan to achieve the targets contained in the Executive Orders, including any necessary legislative initiatives required. The Action Team submitted its Phase One report to the Governor on Nov. 1, 2007. The final report was completed by the October 2008 deadline and included recommendations incorporating GHG emission reduction targets and strategies into Floridas energy future as well as energy efficiency and conservation targets.
Also in 2008, the state legislature passed broad energy and climate legislation that, among other items, affirmed the FDEPs authority to establish a utility carbon reduction schedule and a carbon dioxide cap and trade system by rule, but added a requirement for legislative ratification of the rule no sooner than January 2010. The FDEP has initiated the rule development process, but until the final rules are developed, the impact on Tampa Electric and its customers cannot be determined. However, if the final rules result in increased costs to Tampa Electric, or further changes in customer usage patterns in response to higher rates, Tampa Electrics operating results could be adversely affected.
A mandatory RPS could add to Tampa Electrics costs and adversely affect its operating results.
In connection with the executive orders signed by the Governor of Florida in July 2007, the FPSC was tasked with evaluating a renewable portfolio target. 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. In addition, there is proposed legislation in the U.S. Congress to introduce a renewable energy portfolio standard 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 a renewable energy portfolio standard, as proposed. Tampa Electrics operating results could be adversely affected if Tampa Electric were not permitted to recover these costs from customers, or if customers change usage patterns in response to increased rates.
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 Electrics 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. There is, however, uncertainty regarding whether the available supply of both domestic and imported natural gas and the existing infrastructure to transport the natural gas into and within Florida are adequate to meet the projected increased demand.
If 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 face today. Tampa Electrics 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 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 Tampa Electric and PGS have historically been granted regulatory approval to recover or defer the majority of significant storm costs incurred, 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 results of operations of the affected company could be materially and adversely impacted.
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 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 and the impact of the housing market slowdown may affect sales at our utility companies.
Tampa Electrics weather-normalized residential per customer usage declined again in 2009, following a decline in 2008. 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, which can be affected by weather, was approximately 8% in 2009 and in 2008.
In general, energy usage per residential customer at both Tampa Electric and PGS has declined over the last three years. We believe that this was in response to weather patterns especially in the spring and fall, voluntary conservation in response to the economic conditions, increased appliance efficiency, and increased residential vacancies as a result of increasing foreclosures amid the economic slowdown.
The utilities forecasts are based on normal weather patterns and historical trends in customer energy use patterns. Tampa Electrics and PGS ability to increase energy sales and earnings could be negatively impacted if energy prices increase in general and customers continue to use less energy in response to economic conditions.
The federal government has injected considerable liquidity into the financial system and supported the housing market through mortgage purchases and tax credits for qualified home buyers. These programs are scheduled to expire at various times in 2010. Our customer and energy sales growth could be negatively impacted by the withdrawal of this financial support.
Our forecast for results in 2010 assumes no customer growth and a slight decrease in energy sales growth, driven primarily by the weak economy. If the housing and new home construction markets contract further following the expiration of the various federal support programs our financial results could be negatively impacted.
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)
Our financial results could be reduced if certain proposed revisions to the U.S. tax code related to foreign earnings are implemented.
The administration has announced initiatives that could substantially reduce our ability to defer U.S. income taxes. These proposals include repealing the deferral of U.S. taxation of foreign earnings; eliminating utilization of, or substantially reducing our ability to claim, foreign tax credits; and eliminating certain tax deductions until foreign earnings are repatriated to the U.S.
The current 2010-2011 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 Coals financial results after 2010.
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. In the normal course of business, TECO Guatemala evaluated its $146.7 million investment in DECA II, including associated goodwill, at Dec. 31, 2009 and determined that the value was not impaired. However, the outcome of the ongoing efforts and a potential arbitration under a DR-CAFTA claim is uncertain, and could impact this determination in the future. See the TECO Guatemala section of Managements Discussion & Analysis for additional discussion of the DR-CAFTA claim.
Problems with operations could cause us to incur substantial costs.
Each of our subsidiaries is subject to various operational risks, including accidents, or 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.
Our computer systems and Tampa Electrics infrastructure may be subject to cyber (primarily electronic or internet based) attack, which could disrupt operations, cause loss of important data or compromise customer, employee-related or other critical information or systems.
There have been an increasing number of cyber attacks on companies around the world, which have caused operational failures or compromised sensitive corporate or customer data. These attacks have occurred over the internet, through malware, viruses, or attachments to e-mails or through persons inside of the organization or with persons with access to systems inside of the organization.
We have security systems and infrastructure in place to prevent such attacks, and these systems are subject to internal, external and regulatory audits to ensure adequacy. Despite these efforts, we can not be assured that a cyber attack will not cause electric or gas system operational problems, disruptions of service to customers, or compromise important data or systems.
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 resulting in a backlog of permit applications and very few permits being issued. Our coal company has 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. To date, there has been no progress in granting these permits. 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.
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 Guatemalas operations are exposed to increased risks as the countrys government and regulatory authorities seek ways to reduce the cost of energy to its consumers.
The purchased power agreement between the Alborada Power Station in Guatemala and EEGSA is scheduled to expire in September 2010. If the contract is not renewed the financial results from TECO Guatemala would be reduced.
In 2001, EEGSA granted TECO Guatemala an option to extend the Alborada power sales contract, which is scheduled to expire in September 2010, for five years at the end of the contract period. The tariff to pass through cost associated with the contract was approved by the Guatemalan regulators at that time. The current Guatemalan regulators have objected to the extension citing modifications to regulations passed in 2007. TECO Guatemala is currently in talks with the Guatemalan government to extend this contract. If the contract is not renewed, the net income from the plant would be reduced or eliminated and an impairment charge could be taken.
If efforts to have the July 2008 value added distribution tariff (VAD) decision at EEGSA recalculated or revised are unsuccessful, earnings and cash flow from that company would be at risk as long as the current lower VAD remains in place.
In January 2009, our subsidiary, TECO Guatemala Holdings, LLC, delivered a Notice of Intent to the Guatemalan government indicating its intent to file an arbitration claim against the Republic of Guatemala under the Dominican-Republic-Central America-United States Free Trade Agreement (DR-CAFTA). The required 90-day waiting period has passed and TECO Guatemala now has the ability to file a claim under DR-CAFTA when it deems it is appropriate. In 2009 TECO Guatemala attempted to resolve the dispute amicably through consultation or negotiation and through the Guatemalan legal system, without success. If these efforts continue to be unsuccessful, EEGSAs earnings contribution to TECO Guatemala, estimated to be a minimum of $10 million annually, could be at risk as long as the lower VAD remains in effect.
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 Electrics business and its expected performance.
The gas distribution industry has been subject to competitive forces for several years. Gas services provided by PGS are now unbundled for all non-residential customers. Because PGS earns margins on distribution of gas but not on the commodity itself, unbundling has not negatively impacted PGS results. However, future structural changes that 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 could adversely affect our financial results.
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. We have debt maturities, beginning in 2010, which will require refinancing. Future capital market conditions could limit our ability to raise the capital we need, 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, the recent 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 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, 2009 our plan was more than 100% funded under calculation requirements of the Pension Protection Act (PPA). However, as a result of the
continued low interest rate environment, our funded percentage is expected to be approximately 90% as of the Jan. 1, 2010 PPA measurement date. This will increase our required contributions to the plan beginning in 2010. 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 2010 will be higher than in 2009, due in large part to the lower interest rate environment (lower discount rates used to measure our Plans benefit obligations). 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.
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 MD&A for descriptions of these tests and covenants.
As of Dec. 31, 2009, 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 Off-Balance Sheet Debt and Liquidity, Capital Resources sections of the MD&A.
Our financial condition and results could be adversely affected if our capital expenditures are greater than forecast.
We are forecasting lower levels of capital expenditures, primarily at Tampa Electric, for compliance with our environmental consent decree, to support the current levels of slower 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 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 & Poors (S&P) at BBB- with a stable outlook, by Moodys Investors Services (Moodys) at Baa3 with a stable outlook, and by Fitch Ratings (Fitch) at BBB- with a stable outlook. The senior unsecured debt of Tampa Electric Company is rated by S&P at BBB with a stable outlook, by Moodys at Baa1 with a stable outlook and by Fitch at BBB+ with a stable 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 Companys consolidated shareholders equity is lower than $500 million. At Dec. 31, 2009, Tampa Electric Companys consolidated shareholders equity was approximately $2.1 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 MD&A).
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.
We are vulnerable to interest rate changes and may not have access to capital at favorable rates, if at all.
A portion of our debt bears interest at variable rates. Increases in interest rates, therefore, may require a greater portion of our cash flow to be used to pay interest. In addition, changes in interest rates and capital markets generally affect our cost of borrowing and access to these markets.
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 has four electric generating plants in service, with a December 2009 net generating capability of 4,719 MW. Tampa Electric assets include the Big Bend Power Station (1,602 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 (235 MW capacity from the IGCC unit and 732 MW capacity from four CTs) and a partnership interest with the City of Tampa on 6 MW net winter generating capability from the Howard Current Advanced Waste Water Treatment Plant.
The Big Bend coal 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 in January 2004, Units 5 and 6 were completed in April of 2009 and Units 3 and 4 were completed in July 2009.
Tampa Electric owns 178 substations having an aggregate transformer capacity of 22,248 Mega Volts Amps (MVA). The transmission system consists of approximately 1,309 pole miles (including underground and double-circuit) of high voltage transmission lines, and the distribution system consists of 6,413 pole miles of overhead lines and 4,472 trench miles of underground lines. As of Dec. 31, 2009, there were 668,157 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.
Operations of TECO Coal and its subsidiaries are conducted on both owned and leased properties totaling over 250,000 acres in Kentucky, Tennessee and Virginia. TECO Coals 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 to less significant properties are now verified during lease or purchase negotiations.
In situations where property is controlled by lease, the lease terms are generally sufficient to allow the reserves for the associated operation to be mined within the initial lease term. In fact, the terms of many of these leases extend until the exhaustion of the mineable and merchantable coal from the leased property. If, however, extensions of the original lease term become necessary, provisions have generally been made within the original lease to extend the lease term upon continued payment of minimum royalties.
As of Dec. 31, 2009, the TECO Coal operating companies had a combined estimated 262.2 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 Coals 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 67.5 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) ReservesReserves 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) ReservesReserves 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 Coals reserve estimates are prepared by its staff of geologists, whose experience ranges from 20 years to 35 years. TECO Coal also has two chief geologists with the responsibility to track changes in reserve estimates, supervise TECO Coals other geologists and coordinate third party reviews of our reserve estimates by qualified mining consultants. In 2009, a third-party reserve audit was performed by Marshall Miller & Associates on the portion of reserves acquired during 2009. The results of that audit are reflected in the numbers within this report.
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 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)
HVMHigh Vol Met
LSULow Sulfur Utility
PCIPulverized Coal Injection
Reserve Estimation Procedure
TECO Coals reserves are based on over 2,900 data points, including drill holes, prospect measurements and mine measurements. Our reserve estimates also include information obtained from our on-going exploration drilling and in-mine channel sampling programs. Reserve classification is determined by evaluation of engineering and geologic information along with economic analysis. These reserves are adjusted periodically to reflect fluctuations in the economics in the market and/or changes in engineering parameters and/or geologic conditions. Additionally, the information is constantly being updated to reflect new data for existing property as well as new acquisitions and depleted reserves.
This data may include elevation, thickness, and, where samples are available, the quality of the coal from individual drill holes and channel samples. The information is assembled by qualified geologists and engineers located throughout TECO Coal. Information is entered into sophisticated computer modeling programs from which preliminary reserves estimations are generated. The information derived from the geological database is then combined with data on ownership or control of the mineral and surface interests to determine the extent of the reserves in a given area. Determinations of reserves are made after in-house geologists have reviewed the computer models and manipulated the grids to better reflect regional trends.
During TECO Coals 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, are considered when mining near or under such facilities. Also, as part of TECO Coals reserve and mineability evaluation, TECO Coal reviews legal, economic and other technical factors. Final review and recoverable reserve determination is completed after a thorough analysis by in-house engineers, geologists and finance associates.
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.
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 companys results of operations or financial condition.
For a discussion of the resolution of previously disclosed legal proceedings and an update of previously disclosed environmental matters, see Notes 12 and 8, Commitments and Contingencies, of the TECO Energy, Inc. and Tampa Electric Company Consolidated Financial Statements, respectively.
No matter was submitted during the fourth quarter of 2009 to a vote of TECO Energys security holders, through the solicitation of proxies or otherwise.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages, current positions and principal occupations during the last five years of the current executive officers of TECO Energy are described below.
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 5, 2010, and until such officers successor is elected and qualified.
The following table shows the high and low sale prices for shares of TECO Energy common stock, which is listed on the New York Stock Exchange, and dividends paid per share, per quarter.
The approximate number of shareholders of record of common stock of TECO Energy as of Feb. 22, 2010 was 14,655.
Dividends on TECO Energys 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 Energys $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. 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 ResourcesCovenants 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 Companys 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 $179.6 million in 2009, $159.9 million in 2008, and $166.1 million in 2007. 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.
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, 2009, 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, 2004 and that all dividends were reinvested.
This Managements 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 Managements Discussion & Analysis, we, our, ours and us refer to TECO Energy, Inc. and its consolidated group of companies, unless the context otherwise requires.
We are an energy-related holding company with four businesses consisting of 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 distribution and energy-related businesses in Guatemala.
Our regulated utility companies, Tampa Electric and PGS, operate in the Florida market. Tampa Electric serves almost 667,000 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 4,719 megawatts. PGS, Floridas largest gas distribution utility, serves more than 334,000 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 more than 1.4 billion therms in 2009.
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 2009 were 8.7 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. It also has a 24% ownership interest in Guatemalas largest distribution utility, Empresa Eléctrica de Guatemala (EEGSA), and in affiliated companies (in combination called DECA II), which provide, among other things, electricity transmission services, wholesale power sales to unregulated electric customers and engineering services.
In December 2007, we sold TECO Transport, a dry-bulk shipping company that had been a part of our business mix for many years. We used the cash from this sale to further our most important cash priorities, investing in our Florida utilities and reducing parent company debt. The sale of TECO Transport allowed us to accelerate the retirement of parent debt, improve our balance sheet and credit ratings and reduce our business risk profile.
We have reduced parent and parent-guaranteed debt from a peak level of $2.7 billion in 2002 to $1.3 billion at the end of 2009. This debt was incurred in connection with a series of major investments in unregulated domestic power generation facilities outside Florida in anticipation of a movement toward competitive energy. The investments were ultimately unsuccessful and resulted in substantial losses when we exited this business segment in 2004 and 2005.
All amounts included in this Managements Discussion & Analysis are after tax, unless otherwise noted.
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 Guatemalas 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 reflect the benefits of higher base rates at Tampa Electric and PGS effective in 2009, and improved margins at TECO Coal as a result of higher selling prices. At TECO Guatemala, results reflect 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 2008, our net income and earnings per share attributable to TECO Energy were $162.4 million or $0.77 per share, compared to $413.2 million or $1.97 per share in 2007. Net income in 2008 included a $21.6 million provision for taxes due to the repatriation of cash and investments from Guatemala, a $1.9 million charge associated with a regulatory settlement with the Florida Public Service Commission (FPSC) related to a dispute that arose in 2008 over the calculation of Tampa Electrics waterborne transportation disallowance over its five-year life, and $2.6 million of favorable adjustments to income taxes and working capital related to the sale of TECO Transport.
Our non-GAAP results in 2008, which exclude the charges and gains discussed above, on a per share basis were $0.87 per share, compared to $1.07 in 2007, which excluded charges, gains and the benefits from the production of synthetic fuel (see the 2008 and 2007 Reconciliation of GAAP net income from continuing operations to non-GAAP results tables). Our results in 2008 reflected the impact on Tampa Electric of lower customer and energy sales growth, and the impact on TECO Coal of higher production costs. Performance in 2008 benefited from improved results at PGS and TECO Guatemala (excluding the taxes on the repatriation of cash and investments), and lower parent interest expense as a result of our debt retirement actions.
Net income attributable to TECO Energy in 2007 included the $149.4 million gain from the sale of TECO Transport, $16.3 million of costs related to the sale of TECO Transport, and $20.2 million of charges related to debt extinguishment/exchange transactions. TECO Transport and the production of synthetic fuel contributed $34.0 million and $52.6 million, respectively, or $0.41 per share collectively, to 2007 net income. In 2007, net income reflected a $14.3 million tax benefit recorded in discontinued operations related to the 2005 disposition of the Union and Gila River merchant power plants.
In 2009, we focused on concluding the base rate proceedings at both utilities and completion of peaking generation capacity additions and rail unloading facilities at Tampa Electric. In July 2009, we announced restructuring actions as part of our response to the lower customer and energy sales growth in the current economic downturn, industry changes, and the overall need to maintain a lean and efficient organization. We restructured the organization to establish a single management team over the electric and gas divisions of Tampa Electric Company, and integrated operating and support functions. These actions have reduced our expected 2010 operations and maintenance expenses to slightly above 2008 levels, and are expected to largely offset the effects of lower growth than expected at the time of the base rate filing.
We remain focused on supporting the growth of Tampa Electric and strengthening its capital structure through equity contributions from TECO Energy to Tampa Electric. Tampa Electric has ongoing capital requirements associated with reliably and efficiently serving its customer base. To accomplish our objectives of supporting Tampa Electrics growth and reducing parent debt, in 2007 we completed the sale of TECO Transport for $405 million of gross proceeds. The sale allowed us to accelerate the retirement in 2007 of almost $300 million of parent debt and $111 million of parent-guaranteed debt. The accelerated debt retirement allowed us to deploy cash generated in 2008 to investment in Tampa Electric that otherwise would have been applied to debt reduction.
We remain focused on our long-term goal of investing in and growing our Florida utility businesses, while generating cash and earnings from our other energy-related businesses, TECO Coal and TECO Guatemala. Continued reduction of parent debt that remains from the unsuccessful merchant power investments made early in the last decade remains a priority as well.
Important factors in our 2010 results will be the individual operating company factors discussed below.
Tampa Electric and PGS are under a single management team with new organizational structures following the restructuring actions taken in the third quarter of 2009. These actions have reduced expected operations and maintenance expenses, excluding all FPSC approved recovery clauses, in 2010 to approximately 2008 levels to offset the approximately $40 million revenue shortfall that resulted from lower customer and energy sales growth than projected in their base rate cases. These actions are expected to enable the utilities to earn the authorized returns on equity set in their 2009 rate case decisions.
Tampa Electric and PGS will have the full year benefit of the new base rates approved by the FPSC in 2009, and, effective Jan. 1, 2010, $25.7 million of rates approved in 2009 related to the five combustion turbines and the rail unloading facilities placed in service in 2009. The 2010 portion of the base rate revenues effective Jan. 1, 2010 are subject to refund pending the outcome of a hearing to be held by the FPSC in 2010 (see the Regulatory section).
The forecast for Tampa Electric and PGS assumes normal weather for the full year. The outlook and timing for a Florida economic recovery remains uncertain due to high unemployment and a weak housing market. Some economists are forecasting a very slow recovery starting about the middle of 2010, while others are forecasting a flat economy for 2010. The forecast used by Tampa Electric and PGS assumes no recovery in customer growth in 2010 and a slight decline in energy sales due to lower
customer usage in response to the continued weak economy. The Florida housing market is not expected to start to recover until after a general economic recovery begins. Until the economy and housing markets start to improve, it is difficult to forecast when customer and related energy sales growth will resume.
Excluding all FPSC approved recovery clauses, Tampa Electrics non-fuel operation and maintenance expense is expected to decrease in 2010 compared to 2009 as a result of the restructuring actions taken in 2009. Depreciation expense is expected to increase from additions to facilities to serve customers; and interest expense is expected to increase due to higher long-term debt balances associated with the construction program. Environmental Cost Recovery Clause-related earnings are expected to increase due to the completion of the fourth, and final, nitrogen oxide (NOx) control project, which is expected to enter service in May. Allowance for Funds Used During Construction (AFUDC) is expected to decrease significantly in 2010 due to the 2009 completion of the peaking generation units and the 2010 completion of the NOx control projects. In November 2009, the FPSC approved Tampa Electrics fuel cost recovery filing, which included full recovery of waterborne and rail transportation costs for the delivery of solid fuel.
In 2010, customer and therm sales growth at PGS will be impacted by the uncertain timing of economic and housing market recoveries. Excluding all FPSC-approved cost recovery clause-related expenses, operation and maintenance expense is expected to decrease in 2010. Depreciation expense is expected to increase due to normal additions to facilities to serve customers.
TECO Coal expects 2010 net income to increase over 2009 from higher contract selling prices. Total sales are expected to be in a range between 8.3 and 8.7 million tons in 2010, compared to 8.7 million tons in 2009. This lower level of expected production is in response to the current world-wide market conditions for steam and metallurgical coal. The full expected sales of all products are currently contracted at an average selling price of approximately $75 per ton. In 2010, the sales mix is expected to be closer to historical averages of one-third specialty coals (metallurgical, pulverized coal injection (PCI) and stoker) and two-thirds utility steam coal. The fully-loaded, all-in cost of production is expected to be in a range between $65 and $69 per ton driven by lower diesel fuel costs offset by higher safety requirements, productivity that reflects the industry-wide trend of increased inspections by state and federal agencies, and higher royalty costs and severance taxes due to the higher selling prices. Diesel fuel prices have been hedged for those contracts that do not have diesel price adjustments in the contract at average prices significantly below 2009 hedged levels.
TECO Guatemala expects improved operating and financial performance at the San José Power Station following the extended unplanned outages in 2009, and higher contract capacity payments, which are expected to increase as the 12-month rolling average capacity factor improves. Due to the unplanned outages in 2009, the 12-month rolling average contract availability for San José Power Station fell below the required level, which caused the capacity payments to be reduced. Spot energy sales are expected to increase due to higher residual (#6 oil) oil prices, which is the fuel used by other generators. The dispatch price for some of the diesel generating resources in Guatemala, which use residual fuel oil, is above the dispatch price for the San José Power Station, which includes the cost of coal plus a non-fuel variable cost component. TECO Guatemala is currently in talks with the Guatemalan regulatory authorities regarding the five-year extension of the power sales contract for the Alborada Power Station, which expires in September 2010. In August 2008, the Guatemalan regulatory body, CNEE, unilaterally reduced the distribution tariff (VAD) for EEGSA. TECO Guatemala Holdings, LLC has served a Notice of Intent under the Dominican-Republic-Central America-United States Free Trade Agreement (DR-CAFTA) indicating its intent to file an arbitration claim against the Republic of Guatemala for damages to its EEGSA partnership interest as a result of the VAD decision. There have been hearings in the Guatemalan courts on EEGSAs actions, which have been resolved against EEGSA, and Iberdrola, EEGSAs largest investor, is in an international arbitration process under the bilateral trade agreement between Spain and Guatemala, but the issue with the VAD remains unresolved with no firm schedule to resolve this matter (see the TECO Guatemala section). The 2010 outlook for TECO Guatemala assumes that the VAD issue remains unresolved.
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. We expect to make additional equity contributions to Tampa Electric and PGS in 2010 to support their capital spending programs.
Capital expenditures increased in 2009, primarily at Tampa Electric for equipment to control NOx emissions, peak load generating capacity expansion, installation of rail coal unloading facilities, compliance with the FPSC-mandated transmission and distribution system storm hardening requirements, distribution system reliability improvement, and heat rate and capacity factor improvements to our coal-fired units. We also invested in new mining equipment and continued development of mines at TECO Coal. We forecast capital expenditures of $305 million in 2010 at Tampa Electric and to remain at about that level for the next several years. This level of capital spending will allow Tampa Electric to meet generation plant maintenance and the expected resumption of customer growth. It will also allow for distribution system improvements to provide higher reliability and for expansion of its transmission system. We also plan to invest in modest distribution system expansion at PGS, and normal maintenance capital and regulatory compliance at TECO Coal in 2010 (see the Liquidity, Capital Resources section). Due to the slow down in the Florida economy in 2008 and 2009 and a lower near-term growth outlook, this forecast excludes any base load generating capacity additions, which were previously forecasted for the 2013 period. It also excludes any amounts for investments in renewable energy sources, which could be required under certain legislative proposals at the state and federal levels.
Since July 2006, we have provided two measures to allow comparison of our results with and without synthetic fuel. They are non-GAAP results from continuing operations including benefits from the production of synthetic fuel (Non-GAAP Results With Synthetic Fuel), which exclude certain charges and gains, but include synthetic fuel benefits or costs, and non-GAAP results excluding synthetic fuel (Non-GAAP Results Excluding Synthetic Fuel), which exclude charges, gains and benefits associated with the production of synthetic fuel (see the Non-GAAP Information section). Although, with the expiration of the synthetic fuel tax credits at the end of 2007, we no longer produce synthetic fuel, we are continuing to provide both non-GAAP measures for historical comparison purposes.
The table below compares our GAAP net income to our non-GAAP measures. A reconciliation between GAAP net income and the two non-GAAP measures is contained in the Reconciliation of GAAP net income from continuing operations to non-GAAP results tables included 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).
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. In 2007, net income and earnings per share attributable to TECO Energy were $413.2 million or $1.97 per share, which included the gain on the December 2007 sale of TECO Transport. 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. Non-GAAP results in 2007 were $223.7 million or $1.07 on a per-share basis (see the 2009 and 2008 Reconciliation of GAAP net income from continuing operations to non-GAAP results tables). TECO Transport and the production of synthetic fuel contributed $34.0 million and $52.6 million, respectively, or $0.41 per share collectively, to 2007 net income. 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 $21.6 million and $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.
For 2007, as a result of the sale transaction, results at TECO Transport were included only through Dec. 3, 2007. Net income and earnings per share were $413.2 million or $1.97 per share in 2007, and included the $149.4 million gain and the $16.3 million of costs related to the sale of TECO Transport, and $20.2 million of charges related to the debt extinguishment/exchange transactions completed in December. Net income and earnings per share attributable to TECO Energy before discontinued operations were $316.7 million or $1.51 per share in 2007, and reflected a $14.3 million tax benefit recorded in discontinued operations in the second quarter as a result of reaching a favorable conclusion with taxing authorities related to the 2005 disposition of the Union and Gila River merchant power plants. TECO Transport was not classified as a discontinued operation due to its ongoing contractual relationship with Tampa Electric for solid fuel waterborne transportation services.
Results in 2007 included a $52.6 million, or $0.25 per share, benefit to earnings from synthetic fuel production (see the TECO Coal section).
2009 Earnings Summary
The following tables show the specific adjustments made to GAAP net income for each segment to develop our non-GAAP results:
2009 Reconciliation of GAAP net income from continuing operations to non-GAAP results
2008 Reconciliation of GAAP net income from continuing operations to non-GAAP results
2007 Reconciliation of GAAP net income from continuing operations to non-GAAP results
From time to time, in this Managements 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 companys 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 limited to those that we believe are not indicative of future performance.
This Managements Discussion & Analysis of Financial Condition and Results of Operations utilizes TECO Energys 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).
Electric Operations Results
Net income in 2009 was $160.2 million, compared to $135.6 million in 2008. Tampa Electrics 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.
In 2008, net income was $135.6 million, compared to $150.3 million in 2007. Tampa Electrics 2008 non-GAAP results were $137.5 million, which excluded a $1.9 million charge related to the settlement with the FPSC related to a dispute that arose in 2008 over the calculation of Tampa Electrics waterborne transportation disallowance over its five-year life (see the 2008 Reconciliation of GAAP net income from continuing operations to non-GAAP results table). These results were driven primarily by lower retail energy sales, higher depreciation, lower interest income and higher interest expense, partially offset by higher earnings on emissions control equipment recovered through the Environmental Cost Recovery Clause (ECRC) (see the Environmental Compliance section), and slightly lower operation and maintenance and property tax expense. These results reflect retail energy sales 2.8% lower than in 2007. The average number of retail customers increased 0.1% for the year, which was significantly lower than in prior years, as a result of the slowdown in the Florida economy and housing market. Total heating and cooling degree days were 5% below normal and 8% below 2007 levels.
In 2008, excluding all FPSC-approved cost recovery clause-related expenses, operation and maintenance expense decreased $0.8 million, compared to 2007, primarily due to $4.0 million higher spending on generating unit maintenance and repairs and $0.8 million higher bad-debt expense, more than offset by $4.2 million lower employee-related expenses and other smaller cost reductions totaling $0.6 million in aggregate. Property tax expense decreased $0.7 million reflecting adjustments to property valuations agreed to with taxing authorities. Depreciation and amortization expense increased $4.3 million reflecting additional facilities to serve customers. Interest expense increased $1.5 million due to higher interest rates, and interest income decreased $2.9 million due to lower under-recovered fuel balances. Net income also included $6.3 million of AFUDC-equity related to the construction of the peaking generation units and the installation of NOx pollution control equipment, compared to $4.5 million in 2007.
Because of lower customer growth, slower energy sales growth, and ongoing high levels of capital investment, Tampa Electrics 13-month average regulatory ROE was 8.7% at the end of 2008, and 9.2% at the end of 2009. We made cash equity contributions totaling $292 million to Tampa Electric to strengthen its capital structure and to support its capital program in 2008.
Due to the significant decline in ROE, Tampa Electric filed for a $228 million base rate increase in August 2008. In March 2009, the FPSC awarded a $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 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, 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. 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 FPSCs decision to reject their motion for reconsideration of the 2010 portion of base rates approved in 2009. The FPSC and Tampa Electric will oppose this appeal. The intervenors filed appellate briefs on Feb. 24, 2010. There is no specific time frame for a resolution.
In December 2009, the FPSC approved Tampa Electrics 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 $8.3 million to $25.7 million, subject to refund. A regulatory proceeding will be held during 2010 regarding the continuing need for the CTs, the appropriate amount to be recovered and the resulting rates. Pending final FPSC approval, the hearing is tentatively set for the first week of September.
Summary of Operating Results
In 2009 retail megawatt hour sales declined 1.1% 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. Pretax base revenues increased approximately $72 million in 2009 from the higher base rates approved by the FPSC, which were effective in May 2009.
In 2008, retail megawatt-hour sales declined 2.8%, which resulted in a $19.0 million reduction in base revenue, due to milder than normal weather and voluntary conservation by customers, which we believe to be in response to the generally weaker economic conditions. Total heating and cooling degree days were 5% below normal and 8% below 2007 levels.
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 both 2009 and 2008.
Electricity sales to the phosphate industry decreased 6.5% in 2009, following a 7.7% decrease in 2008. The 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 less than 3% of base revenues in 2009 and less than 2% in 2008. Sales to commercial customers decreased 2.0% in 2009, reflecting the weaker local economy.
Fuel-related rates decreased in both 2009 and 2008, after an increase in 2007 under the FPSC-approved fuel cost recovery clause. In March 2009, Tampa Electric filed to lower the fuel component of the customers bill due to an over recovery of fuel costs in 2008 and projected lower fuel costs in 2009. The March 2009 decrease was due to an over-recovery of fuel costs in the final quarter of 2008 from lower natural gas prices than previously forecast and a forecast for continued lower natural gas prices for the remainder of 2009 (see the Regulation section).
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 Electrics base-load coal generation not the lowest cost form of energy for spot sales. Energy sold to other utilities for resale decreased 2.3% in 2008, due to lower coal unit availability in the first six months of the year.
Customer and Energy Sales Growth Forecast
The outlook and timing for a Florida economic recovery remains uncertain due to high unemployment and the weak housing market. Some economists are forecasting a very slow recovery starting about the middle of 2010, while others are forecasting a flat economy for 2010. The forecast used by Tampa Electric reflects no customer growth in 2010 and a slight decline in energy sales due to lower customer usage in response to the continued weak economy. The actual average number of customers declined 0.1% in 2009. There was an increase in the average number of customers in the fourth quarter of 2009, the first such increase in 18 months. 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 in the last quarter. Until unemployment starts to decline and the economy and housing markets start to improve, it will be difficult to forecast when customer and related energy sales growth will resume (see the Risk Factors section).
Longer-term, assuming an economic recovery, and that growth from population increases and business expansion will resume, 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 in the 2011 or 2012 time frame. This energy sales growth projection is lower than previous projections, reflecting changes in usage patterns and changes in population trends. Tampa Electric forecasts that summer retail peak demand growth will be minimal over the next three years, but peak load growth will resume after 2013. These growth projections assume a resumption of local area economic growth, normal weather, a slow recovery in the housing market over time, and a continuation of the current energy market structure.
The economy in Tampa Electrics service area contracted in 2009 and 2008 after modest growth in 2007. Initially, the contraction was centered in housing and related industries, but spread to the general economy later in 2007. The Tampa metropolitan areas employment decreased 5.1% in 2009 following a 2.7% decrease in 2008. This level of job loss is greater than statewide losses in Florida. The local Tampa area unemployment rate increased to 12.4% at year-end 2009, compared with 8.3% at the end of 2008 and 4.7% in December 2007. The Tampa area year-end 2009 unemployment rate was higher than the 11.8% unemployment rate for the state of Florida and higher than the 10.0% for the nation, which is contrary to the trends experienced in previous economic slowdowns. The more severe downturn in the Tampa area and Florida was initially driven by the sharp downturn in construction activity following the boom in the 2005 and 2006 periods, which has since spread to other housing-related businesses and the economy in general.
As in many areas of the country, the housing market in Tampa Electrics service area remained weak in 2009 with declining home prices for much of the year and a high number of foreclosures. This trend was a continuation of the weak housing markets of 2008 and 2007 initially driven by excess builder inventory, the curtailment of speculative investing and sub-prime mortgage issues, and more recently by high unemployment and the tight mortgage lending markets.
In the second half of 2009 there were some positive signals from the housing market in the form of increased sales of existing homes, increases in existing home resale prices in two of the last four months of 2009 as reported by the Case-Shiller Home Price Index, and a modest increase in the number of new single family building permits. Economists and real estate associations indicate that the housing market is expected to remain weak at least through the first half of 2010 with a recovery possibly starting late in 2010, depending on the timing of a general economic recovery and the absorption of excess inventory.
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 in the third quarter.
Total pretax operating expense decreased 4.6% in 2008, driven by lower fuel expense and lower taxes other than income, including lower property taxes and sales-related taxes and lower franchise fees. In 2008, excluding all FPSC-approved cost recovery clause-related expenses, operation and maintenance expense decreased $0.8 million, compared to 2007, primarily due to $4.0 million higher spending on generating unit maintenance and repairs and $0.8 million higher bad debt expense more than offset by $4.2 million lower employee-related expenses, and $1.4 million of other smaller cost reductions. Property tax expense decreased $0.7 million, driven by adjustments to property valuations agreed to with taxing authorities.
Tampa Electric expects operation and maintenance expense, excluding fuel and purchased power, to decrease to approximately 2008 levels in 2010. Excluding all FPSC approved recovery clauses, the 2010 non-fuel operation and maintenance expense decrease is expected to be driven by the restructuring actions taken in 2009, and will better match expenditures to 2010 revenues, which reflect the current state of Floridas economy.
In 2009, depreciation expense increased $9.1 million and taxes other than income were higher due to the peaking combustion turbines placed in service in 2009 and normal additions to facilities to serve customers. Depreciation expense increased $4.3 million in 2008, reflecting additional facilities to serve customers. Depreciation expense is projected to increase in 2010 due to routine plant additions to serve Tampa Electrics customer base and maintain system reliability, a full year of depreciation on combustion turbines that were placed in service at various times in 2009, the addition of solid-fuel rail unloading facilities in late 2009 and a partial year of depreciation on the fourth and final NOx control project, which is expected to enter service in May 2010.
Fuel Prices and Fuel Cost Recovery
In November 2008, the FPSC approved Tampa Electrics 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).
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 include 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).
Total fuel cost increased in 2009, due to higher cost for coal partially offset by lower costs for natural gas. Purchased power decreased in 2009 due to lower natural gas prices, which is the primary fuel used by other generators in Florida. Average delivered coal and natural gas prices moved in opposite directions in 2009. Natural gas prices decreased 24.6% in 2009 due to storage inventories above historic averages resulting from lower demand for natural gas from industrial users caused by the economic recession, and increased supply of low cost gas from domestic sources. Coal costs increased 4.8% in 2009 due to contracts signed in 2008 for deliveries in 2009 when coal prices were higher. Coal and natural gas prices were $3.05 per million BTU (/mmBTU) and $8.00/mmBTU, respectively, in 2009.
Total fuel prices decreased in 2008, but purchased power increased due to lower generation from natural gas fired facilities. Average delivered coal and natural gas prices increased 13.0% and 11.4%, respectively, to $2.91/mmBTU and $10.61/mmBTU, respectively, in 2008.
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 increase in 2010 from the unusually low 2009 levels. Coal prices, while less volatile, decreased in 2009 after sharp increases in 2008 and 2007. Coal prices experienced a significant decline in 2009 for spot or as needed purchases, due to lower demand for coal fired generation of electricity as a result of the economic conditions. Tampa Electrics primary coal supplies are from the Illinois Basin, which experienced an upward movement in prices in 2008 but not of the same magnitude as prices in the Central Appalachian coal producing region. Tampa Electrics coal prices are expected to remain stable in 2010 due to longer-term supply contracts signed in 2008.
On a retail energy supply basis, Tampa Electric generation accounted for 98%, 94% and 93% of the total retail energy sales in 2009, 2008 and 2007, respectively, with the remainder of the energy supplied by purchased power. Purchased power expense decreased 41.8% due to the lower per-unit prices associated with the purchases as a result of lower natural gas prices and lower volumes purchased primarily due to lower demand and improved coal-fired unit availability during the high-load summer period. Purchased power expense is expected to decrease in 2010 due to a lower volume of purchases driven by only one planned outage for the final SCR installation compared to multiple SCR outages in 2009.
Prior to 2003, nearly all of Tampa Electrics 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. In 2009, at times it was more cost effective to generate electricity from natural gas than from coal due to the low natural gas prices. Nevertheless, coal is expected to continue to represent more than half of Tampa Electrics fuel mix due to the baseload units at the Big Bend Power Station and the coal gasification unit, Polk Unit One. In 2010, the final Big Bend Power Station coal-fired unit will undergo an extensive outage to complete the construction of the NOx control equipment (see the Environmental Compliance section), which is expected to reduce the generation from coal from that unit. Anticipated higher natural gas prices in 2010 are expected to increase the use of coal for generation.
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 utilitys system. Future capital expenditures required under the storm hardening program are expected to average more than $20 million annually for the foreseeable future (see the Regulation section).
For the past several years, 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 expects to make additional capital investments in its transmission and distribution system to improve reliability and reduce customer outages, and for generating unit reliability.
Due to the dramatic slowdown in the Florida and national economies and the Florida housing market in 2008 and 2009, Tampa Electric has 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 or peaking 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 2010 legislative session, Tampa Electric may need to invest capital to develop additional sources of renewable power generation.
PEOPLES GAS (PGS)
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 reflect a $4.0 million favorable adjustment to previously recorded deferred tax balances, and the new base rates effective in June, partially offset by higher non-fuel operations and maintenance expenses and depreciation. Results reflect 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 was 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.
In 2009, the total throughput for PGS was 1.4 billion therms. Industrial and power generation customers consumed approximately 50% of PGS annual therm volume, commercial customers used approximately 26%, approximately 19% was sold off-system, and the balance was consumed by residential customers.
PGS reported net income of $27.1 million in 2008, compared to $26.5 million in 2007. Results reflected higher volumes for weather-sensitive residential and small commercial customers due to colder than normal weather in the northern portion of Florida in the fourth quarter, which more than offset mild weather earlier in the year. Higher volumes transported for industrial customers and higher volumes for off-system sales offset lower volumes for power generation customers. Average customer growth of 0.2% was a result of the continued weak Florida housing market. Therm sales to industrial customers increased due to two new customers with significant usage but at lower transportation rates, which partially offset lower volumes for other customers due to the economic conditions. Sales to commercial and industrial customers were impacted by the weak Florida housing market and overall weak economy, which reduced sales to customers such as restaurants and wallboard, asphalt and concrete producers. Results also reflect 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 a power generation customer.
In 2008, the total throughput for PGS was 1.4 billion therms. Industrial and power generation customers consumed approximately 45% of PGS annual therm volume, commercial customers used approximately 26%, approximately 23% was sold off-system, and the balance was consumed by residential customers.
Residential operations were about 30% of total revenues in 2009 due to lower natural gas prices. 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.
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.
Excluding restructuring charges, 2009 non-fuel operations and maintenance expense increased $3.3 million compared to 2008 levels when operations and maintenance expense included 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. Absent the 2008 benefits, operations and maintenance expense was essentially unchanged in 2009.
In 2008, excluding costs recovered through the FPSC-approved conservation clause, operation and maintenance expenses decreased $1.2 million, driven primarily by a benefit to environmental remediation expenses discussed above and lower employee-related expenses. Depreciation expense increased $1.1 million due to additions to facilities to serve customers.
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 2009 13-month average rate base of $561 million. The new rates were effective Jun. 18, 2009.
Summary of Operating Results
In Florida, natural gas service is unbundled for non-residential customers 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 2009, approximately 15,200 out of 31,400 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 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 is 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.
In 2010, customer growth and therm sales growth at PGS will be impacted by the uncertain timing of economic and housing market recoveries. Excluding all FPSC-approved cost recovery clause-related expenses, operation and maintenance expense is expected to decrease in 2010 as a result of the 2009 restructuring. Depreciation expense is expected to increase from continued capital investments in facilities to reliably serve customers. Base rate relief was granted in 2009, which amounts to $19.2 million on an annualized basis effective in June 2009.
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 2010, 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).
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 the Florida Gas Transmission Company (FGT) through 59 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 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 reflects 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 Coals effective income tax rate was 17%.
TECO Coal recorded net income of $18.0 million in 2008, compared to $90.9 million in 2007 on sales of 9.3 million tons, compared to 9.2 million tons, which included 6.0 million tons of synthetic fuel, in 2007. TECO Coals 2007 Non-GAAP Results Excluding Synthetic Fuel, which excluded the $52.6 million benefit associated with the production of synthetic fuel, were $38.3 million (see the 2007 Reconciliation of GAAP net income from continuing operations to non-GAAP results table).
Results in 2008 reflected an average net selling price per ton across all products, which excluded transportation allowances, almost 7% higher than in 2007. Due to the signing of steam coal contracts for 2008 delivery during periods of lower prices in 2006 and 2007 and its 2008 metallurgical coal contracts early in the renewal cycle in late 2007, TECO Coal realized lower average prices per ton in 2008 than other coal producers realized from contracts signed during the period of very strong coal markets in 2008. The cash cost of production increased 14% in 2008 compared to 2007, driven by diesel oil prices that were 42% higher than 2007 prices, higher per-ton costs for steel products used in underground mining, higher costs for explosives used in surface mining operations, and higher costs associated with contract miners. The cost of production in 2008 also reflected the industry-wide issues of a shortage of qualified miners and lost productivity due to increased safety inspections, and difficult geology at several TECO Coal mines at various times during the year. Results also reflected a $2.6 million benefit from a contract settlement related to future coal sales, and a $0.6 million benefit from the true-up of the 2007 synthetic fuel tax credit rate, compared to a $1.6 million benefit in 2007 for the true-up of the 2006 rate.
Net income in 2007 reflected $52.6 million of benefits from the production of synthetic fuel. The tax credit program for the production of synthetic fuel expired Dec. 31, 2007.
TECO Coal Outlook
We expect TECO Coals net income to increase in 2010 over 2009 from higher contract selling prices. TECO Coal expects sales to be in range between 8.3 and 8.7 million tons. The total expected sales are contracted and priced at an average price of more than $75 per ton. More than one-third of sales are to steel producers and specialty stoker coal users with the remainder sold to utility steam coal customers. The all-in, fully-loaded production costs are expected to be in a range between $65 and $69 per ton, driven by lower diesel fuel costs offset by higher safety requirements, productivity that reflects the industry-wide trend of increased inspections by state and federal agencies, and higher royalty cost and severance taxes due to the higher selling prices. Diesel fuel prices have been hedged for those contracts that do not have diesel price adjustments in the contract at average prices below 2009 levels.
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 has 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. Production from a mine affected by one of those permits that has been delayed is included in the 2010 sales projections. This mine is expected to contribute approximately 3% of 2010 sales. To date, there has been no progress in granting these permits. TECO Coal is currently producing from other mines to offset the lost production from the delayed permit.
Following the rapid increase in coal prices that started late in 2007, in the third quarter of 2008, in response to the U.S. economic recession, the prices for many commodities, which had previously experienced very strong and very volatile prices in 2008, 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 February 2010, Coal industry newsletters reported that spot prices for high quality metallurgical coal were approaching $200 per metric ton delivered to the customer.
Demand for coal used by utilities to generate electricity declined in 2009 due to the economic recession. Natural gas prices, as measured on a cent per million BTU basis, being below coal prices allowed utilities to substitute natural gas for coal in the generation of electricity. Further, demand for electricity, especially by industrial users across the country, decreased due to the recession. As a result, utility coal stockpiles were significantly above long-term averages, which caused some utilities to defer contracted tons into future years and to not purchase coal in the spot markets as they normally would. All of these factors caused prices for utility steam coal, as measured by reported spot market prices, to drop below $50 per ton for coal from Central Appalachia in 2009, which is less than 50% of the 2008 levels.
In 2010, cold weather early in the year, a recovery in electricity usage by industrial customers, higher natural gas prices, and the improving world economy may cause utilities to again seek new coal supplies, but probably not until the second half of 2010.
The significant factors that could influence TECO Coals results in 2010 are the cost of production and the ability of customers to accept their full 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).
Our TECO Guatemala operations consist of two power plants operating in Guatemala under long-term contracts and an ownership interest in DECA II, which has an ownership interest in Guatemalas largest distribution utility, Empresa Eléctrica de Guatemala (EEGSA) and affiliated energy-related companies which provide, among other things, electricity transmission services, wholesale power sales to unregulated electric customers, and engineering services. The San José and Alborada power stations in Guatemala both have long-term power sales contracts. TECO Guatemalas effective 24% ownership interest in EEGSA is held jointly with partners Iberdrola Energia, S.A. of Spain (Iberdrola) and Electricidad of Portugal (EDP). Together, TECO Guatemala, Iberdrola and EDP own an 81% controlling interest in DECA II. TECO Guatemala has a 30% interest in DECA II.
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 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 countrys 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, EEGSA and Alborada entered into an agreement (the Option) to extend the term of the Alborada power sales contract, which is scheduled to expire in September 2010, for five years at the end of the contract period. At the time of the execution of the Option (2001), the Guatemalan regulators expressly approved the pass through to the tariff of all costs associated with the extended term of the contract, however, even though Alborada is in compliance with all of the terms of the Option, the current Guatemalan regulator has objected to the extension citing modifications to regulations passed in 2007. Alborada is currently in talks with the Guatemalan government to extend this contract term.
In Guatemala, the VAD charges applicable in the tariffs charged by EEGSA are normally reset for new five-year terms. In the summer of 2008, the VAD was expected to be reset in a manner similar to the process utilized in 2003, in accordance with applicable Guatemalan law.
On Jul. 25, 2008, the National Electric Energy Commission (CNEE), the Guatemalan regulatory body, issued a communication unilaterally disbanding the panel of experts appointed under existing regulations to review and approve the new VAD. EEGSA expected that the panels action was going to result in increased rates. On Aug. 1, 2008, CNEE issued resolutions setting new tariff rates for EEGSA, which deviated significantly from the rates calculated consistent with the panel of experts guidance. The VAD revenues resulting from the new rates are approximately 30% 40% below the prior level, essentially putting all of EEGSAs earnings, in which our subsidiary, TECO Guatemala Holdings, LLC, (TGH) shares, which had previously averaged about $10 million annually, at risk during the time this tariff remains in effect.
As a result of these actions, in January 2009, our subsidiary, TGH delivered a Notice of Intent to the Guatemalan government indicating its intent to file an arbitration claim against the Republic of Guatemala under the DR-CAFTA. TGH continues to evaluate its options related to a DR-CAFTA filing (see the Risk Factors section). In the normal course of business, TECO Guatemala evaluated its $146.7 million investment in DECA II, including associated goodwill at Dec. 31, 2009 and determined that the value was not impaired. However, the outcome of the ongoing efforts and a potential arbitration under a DR-CAFTA claim is uncertain, and could impact this determination in the future (see Note 12 to the TECO Energy Consolidated Financial Statements).
EEGSA, Iberdrola, EEGSAs largest investor, and EEGSAs other investors have actively pursued legal and other efforts in Guatemala to remedy CNEEs actions which have been resolved against EEGSA. Through Dec. 31, 2009, these efforts had not resolved the dispute and TGH has until 2011 to initiate a claim under the DR-CAFTA . Iberdrola is in international arbitration under the bilateral trade treaty in place between the Republic of Guatemala and the Kingdom of Spain.
In 2009, TECO Guatemalas net income was $38.6 million, compared to $36.9 million in 2008. TECO Guatemalas 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 reflect 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 reflect 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 28,000 additional customers, or 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 include 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.
In 2008, TECO Guatemalas net income was $36.9 million, compared to $44.7 million in 2007. In December 2008, TECO Guatemala repatriated $71.7 million of cash and investments to TECO Energy, resulting in additional taxes of $9.6 million. TECO Guatemalas full-year 2008 non-GAAP results, which exclude $9.6 million of taxes related to the December 2008 repatriation of cash, were $46.5 million. The San José Power Station realized increased revenues in 2008 from significantly higher prices for spot energy sales. Revenues from contract energy sales increased due to a scheduled price escalation. Higher operating expenses and lower interest income on lower cash balances were essentially offset by lower interest on project debt. EEGSA had 3.9% customer growth in 2008, increasing its customer base by 37,000 to over 877,000 at year-end. The reduction in the VAD tariff at EEGSA starting in August 2008 reduced 2008 earnings at TECO Guatemala approximately $5.0 million. The 2008 results for EEGSA and affiliated companies also included a $3.1 million benefit related to an adjustment to previously estimated 2007 income and year-end equity balances, compared to a similar $1.9 million benefit in 2007.
TECO Guatemala Outlook
In 2010, we expect improved operating and financial performance at the San José Power Station following the extended unplanned outages in 2009, and higher contract capacity payments, which are expected to increase as the 12-month rolling average capacity factor improves. EEGSA, the Guatemalan distribution utility, continues to experience customer and energy sales growth, but the issue with the VAD remains unresolved. There have been hearings in the Guatemalan courts, and Iberdrola, EEGSAs largest investor, is in an international arbitration process under the bilateral trade agreement between Spain and Guatemala.
In 2001, EEGSA and Alborada (a subsidiary of TECO Guatemala) entered into an agreement (the Option) to extend the term of the Alborada power sales contract, which is scheduled to expire in September 2010, for five years at the end of the contract period. At the time of the execution of the Option (2001), the Guatemalan regulators expressly approved the pass through to the tariff of all costs associated with the extended term of the contract; however, even though Alborada is in compliance with all of the terms of the Option, the current Guatemalan regulator has objected to the extension citing modifications to regulations passed in 2007. Alborada is currently in negotiations with the Guatemalan government to extend this contract term as originally intended. If the term of the contract is not extended in accordance with the Option, the net income from Alborada would be reduced or eliminated and an impairment charge could be taken.
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 reflect 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 reflect 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).
Parent/other cost was $55.2 million in 2008, compared to net income of $52.5 million in 2007. In 2008 the non-GAAP cost was $45.8 million, compared to the non-GAAP cost of $60.4 million in 2007. Non-GAAP costs in 2008 exclude $12.0 million of non-cash income taxes on the December 2008 repatriation of cash and investments from TECO Guatemala and a $2.6 million net benefit from adjustments to income taxes and previously estimated costs related to the sale of TECO Transport. Non-GAAP costs in 2007 exclude the $149.4 million net gain on the sale of TECO Transport, $16.3 million of charges related to the sale of TECO
Transport, and the $20.2 million charge related to the debt extinguishment/exchanges completed in December (see the 2008 and 2007 Reconciliation of GAAP net income from continuing operations to non-GAAP results tables). In 2008, interest expense at TECO Energy Parent and TECO Finance, combined, declined $18.5 million reflecting debt retirement actions.
We completed the sale of TECO Transport to an investment group for gross proceeds of $405 million in December 2007. The sale resulted in a net book gain of $149.4 million, before $16.3 million of transaction related costs recorded at TECO Energy parent. Proceeds from the sale of TECO Transport were used to pay down parent level debt on an accelerated basis.
Because of the Assets Held for Sale classification of TECO Transport, the recording of depreciation was discontinued as of Apr. 1, 2007. Net income through Dec. 3, 2007 was $34.0 million and Non-GAAP results were $24.3 million in 2007, including the $9.7 million of depreciation expense that was not recorded in GAAP net income (see the 2007 Reconciliation of GAAP net income from continuing operations to non-GAAP results tables).
OTHER ITEMS IMPACTING NET INCOME
Other income (expense)
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.
In 2007, Other income (expense) of $152.1 million reflected $84.5 million of mark-to-market gains on the oil price hedges on synthetic fuel production at TECO Coal; $68.6 million of pretax income from the Guatemalan operations, which are accounted for as equity investments; $19.4 million of pretax interest income on invested cash balances; and a $32.9 million pretax charge related to the debt extinguishment/exchange .
AFUDC equity at Tampa Electric, which is included in Other income (expense), was $9.3 million, $6.3 million and $4.5 million in 2009, 2008 and 2007, respectively. AFUDC is expected to decrease in 2010 due to the completion of the installation of combustion turbines to meet peak load capacity needs, the rail unloading facilities at Tampa Electrics Big Bend Power Station and for the third NOx control also at Big Bend Power Station (see the Environmental Compliance and Liquidity, Capital Resources sections).
In 2009, total interest expense was $227.0 million compared to $228.9 million in 2008 and $257.8 million in 2007. In 2009, interest expense was reduced by lower interest rates on floating rate debt and higher AFUDC debt at Tampa Electric, which is a credit to interest expense. In 2008, interest expense was reduced by the December 2007 retirement of $297 million of TECO Energy debt and the full-year benefit of other debt retirement in 2007, including the repayment of $300 million of 6.125% notes in May 2007 and the repayment of $111 million of 5% Dock and Wharf bonds in September 2007. Interest expense also reflects Tampa Electric Companys issuance of $100 million of 6.10% notes in July 2009 (see the Financing Activity section).
Interest expense is expected to be higher in 2010 due to higher borrowing levels at Tampa Electric Company, less AFUDC-debt capitalized to construction, and the refinancing of $100 million of low interest rate, floating-rate debt maturing in 2010 (see the Liquidity, Capital Resources section).
The provision for income taxes increased in 2009 primarily 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. The provision for income taxes decreased in 2008 due to lower operating income, the termination of the synthetic fuel operations tax credit program and its related investor income, and the gain recognized on the sale of TECO Transport in 2007. Income tax expense as a percentage of income from continuing operations before taxes was 31.6% in 2009, 36.8% in 2008, and 34.9% in 2007. For 2010, we expect the effective tax rate to be in the range of 30% to 35%.
The cash payments for income taxes, as required by the federal Alternative Minimum Tax rules (AMT), state income taxes and payments (refunds) related to prior years audits totaled $4.1 million, $6.0 million and ($10.5) million in 2009, 2008 and 2007, respectively. The 2007 refund was a result of a 2003 and 2004 foreign tax-credit carryback claim.
In recent years, due to the generation of deferred income tax assets related to the net operating loss (NOL) carryforward from disposition of the generating assets formerly held by TWG Merchant, our unregulated power generation subsidiary which is no longer in that business, cash tax payments for income taxes were 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 2013, at which time we expect to start using more than $190 million of AMT carry-forward to limit future cash tax payments for federal income taxes to the level of AMT. We currently project cash tax payments of approximately $0.5 million in 2010, and less than $3 million in 2011 and 2012. We expect 2013 cash payments to increase to $25 million as a result of having fully utilized the remainder of the NOL.
The tax credit for the production of synthetic fuel expired at the end of 2007. The credit was determined annually and was $0.4103 per million Btu for 2007 after phase-out ($1.2509 per million Btu with no phase-out).
The income tax effect of gains and losses from discontinued operations is shown as a component of results from discontinued operations.
In 2007, net income from discontinued operations reflected a $14.3 million tax benefit recorded in discontinued operations in the second quarter as a result of reaching a favorable conclusion with taxing authorities related to the 2005 disposition of the Union and Gila River merchant power plants. TECO Transport was not classified as a discontinued operation due to the ongoing contractual relationship with Tampa Electric for solid fuel waterborne transportation services.
LIQUIDITY AND CAPITAL RESOURCES
The table below sets forth the Dec. 31, 2009 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.
Consolidated other cash and short-term investments included $19.4 million of cash at the unregulated operating companies for normal operations. In addition to consolidated cash, as of Dec. 31, 2009 unconsolidated affiliates owned by TECO Guatemala, CGESJ (San José) and TCAE (Alborada), had unrestricted cash balances of $24.1 million, which are not included in the table above.
In 2009, we met our cash flow needs primarily from a mix of internal sources supplemented with net borrowings of $57.1 million, of which $102.0 million represented notes issued by Tampa Electric Company (see the Financing Activity section). Cash from operations was $724.7 million. Other sources of cash included $31.6 million of proceeds from the sale of businesses, primarily the sale of our ownership interest in the Guatemalan telecommunications provider, Navega, $5.1 million from the sale of common stock, primarily through dividend reinvestment, and $16.1 million from the sale of student loan securities and other investments. We paid dividends of $170.8 million in 2009, and capital expenditures were $639.8 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. Other sources of cash included net proceeds of $79 million in January associated with the settlement of 2007 oil price hedges related to TECO Coals synthetic fuel program, and $22 million in common stock proceeds. We paid dividends in 2008 of $169 million, and our capital expenditures for the year were $590 million.
In 2007, cash from operations was $554 million. Other sources of cash in 2007 included $405 million from the sale of TECO Transport. We used cash to retire $357 million of TECO Energy parent debt at maturity, $111 million of TECO Energy parent-guaranteed TECO Transport Dock and Wharf bonds at maturity, and $297 million of TECO Energy parent debt prior to maturity, and the regulated companies reduced short-term borrowings $23 million and repaid $150 million of long-term debt at maturity.
Cash from Operations
In 2009, consolidated cash flow from operations was $724.7 million, which was positively impacted by $136.6 million associated with net recoveries of deferred costs, primarily fuel and purchased power, under FPSC-approved recovery clauses. Cash from operations reflects a $6.7 million contribution to the pension plan in 2009.
We expect cash from operations in 2010 to be below the 2009 level. Although we expect higher net income in 2010, we expect the net recoveries under various regulatory clauses to reduce cash from operations. In November 2009, the FPSC approved recovery clause rates that provide for refunds to customers of estimated 2009 net over-recoveries of fuel and purchased power over the 12 months beginning Jan. 1, 2010 (see the Regulation section).
Cash from Investing Activities
Our investing activities in 2009 resulted in a net use of cash of $582.3 million, including capital expenditures totaling $639.8 million. We received $29.0 million in 2009 representing the proceeds from our ownership interest in the Guatemalan telecommunications provider, Navega. Investing activity in 2009 also included 16.1 million received primarily from the sale of student loan securities and other investments.
We expect capital spending for the next several years to be lower, primarily at Tampa Electric due to the 2009 completion of spending on combustion turbines to meet peak load needs and rail unloading facilities for the delivery of coal, and the completion of the fourth and final NOx control project in 2010. Spending to support customer growth at Tampa Electric and PGS is expected to be lower for several years due to the weak Florida economy and housing market. The economic recession and reduction in energy demand statewide has allowed the deferral of certain Central Florida transmission system upgrades (see the Tampa Electric and Capital Expenditures sections).
Cash from Financing Activities
Our financing activities in 2009 resulted in net use of cash of $108.6 million. Major items included $102.0 million of proceeds from Tampa Electric Companys issuance of notes due in 2018, and the repayment of $38.0 million of short-term debt. We paid $170.8 million in common stock dividends, and we received $5.1 million from the sale of common stock from our dividend reinvestment program and exercises of stock options.
In 2010, 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 $100 million of floating rate notes maturing in 2010. See the Cash and Liquidity Outlook section below for a discussion of financing expectations in 2010 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, 2009 our consolidated liquidity was $659.2 million, consisting of $424.8 million at Tampa Electric Company, $215.0 million at TECO Energy parent and $19.4 million at the other consolidated operating companies. In addition, there was $24.1 million of unrestricted cash at the unconsolidated TECO Guatemala operating companies.
We expect our sources of cash in 2010 to include cash from operations at levels below 2009, due in large part to lower net recoveries under various regulatory clauses in 2010 as described above, partially offset by expected higher net income from the operating companies. We plan to use cash generated in 2010 to fund capital spending estimated at $445 million, and for dividends to shareholders. Because of the current favorable interest rate environment, we intend to refinance our $100 million of notes maturing in 2010.
Tampa Electric Company expects to utilize cash from operations and equity contributions from us 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 2010 and remain within the covenant restrictions.
Beyond 2010, our long-term debt maturities for TECO Energy parent and TECO Finance total $364 million in 2011, $336 million in 2012, $200 million in 2015 and $300 million in 2017. Although we plan to retire a portion of these maturities with cash generated internally, because market conditions are currently favorable, on Feb. 22, 2010, we commenced a tender offer to ultimately refinance up to $300 million of the notes with new notes having longer maturities. Tampa Electric Company has two series of notes totaling $650 million maturing in 2012 and will need to issue replacement debt to fund those maturities. The existing bank credit facilities for both Tampa Electric Company and TECO Energy/TECO Finance expire in 2012.
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).
The capital expenditures expected at Tampa Electric Company over the next several years will require additional equity contributions from TECO Energy 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. The 2007 sale of TECO Transport allowed us to use proceeds for the early implementation of parent debt retirement plans and positioned us to redeploy part of the cash planned for parent debt retirement in future years to Tampa Electric Company in the form of significant parent equity contributions in 2008. In addition, through 2012, 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 and expect that our cash payment of income taxes in those years will be less than $3 million.
As a result of our significant debt retirements in 2007 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 Companys ratings were 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, 2009, we could have been required to post additional collateral or settle existing positions with counterparties totaling $37 million, including Tampa Electric Company positions of $36 million. 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 $52 million. None of our credit facilities or financing agreements has ratings downgrade covenants, which would require immediate repayment or collateralization; however in the event of a downgrade our interest expense could be higher.
At Dec. 31, 2009 and 2008, the following credit facilities and related borrowings existed:
Credit facilities, including the one-year accounts receivable facility which was renewed in February 2010, require commitment fees ranging from 7.0 to 60.0 basis points. The weighted average interest rates on outstanding notes payable under the credit facilities at Dec. 31, 2009 and 2008 were 0.66% and 2.65%, respectively.
At Dec. 31, 2009, 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 with a maturity date in March 2010. 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, 2009, the TECO Finance credit facility was undrawn and $6.9 million of letters of credit were outstanding. At Dec. 31, 2009, $55.0 million was drawn on the Tampa Electric Company credit facilities and $0.7 million of letters of credit were outstanding. These credit facilities have financial covenants as identified in Covenants in Financing Agreements section.
At current ratings, TECO Finances and Tampa Electric Companys 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, 2009, the LIBOR interest rate was 0.23%.
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.
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
Companys credit ratings, which total 100 basis points 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 Companys option, either Citibanks 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 Companys 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. 19, 2010 with a Feb. 18, 2011 maturity date.
Covenants in Financing Agreements
In order to utilize their respective bank credit facilities, TECO Energy/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, 2009, 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, 2009. Reference is made to the specific agreements and instruments for more details.
TECO Energy Significant Financial Covenants
Credit Ratings of Senior Unsecured Debt at Dec. 31, 2009
On May 6, 2009, Standard & Poors Rating Services changed its corporate credit rating on TECO Energy, TECO Finance and Tampa Electric Company to BBB from BBB- and changed its outlook to stable from positive. This upgrade resulted in credit ratings for the senior unsecured debt of TECO Energy and TECO Finance of BBB-. This upgrade returned TECO Energys senior unsecured credit rating to investment grade at these three credit rating agencies. As a result many, but not all, of the restrictive covenants in various financing arrangements are no longer applicable.
On May 15, 2009 Moodys Investors Service upgraded Tampa Electric Companys senior unsecured debt to Baa1 from Baa2 and changed its outlook to stable from positive. At the same time Moodys affirmed the ratings for TECO Energy and TECO Finance with stable outlooks at both.
On Jun. 1, 2009, Fitch Ratings affirmed the outstanding ratings of TECO Energy, TECO Finance and Tampa Electric Company, and the outlook remained stable.
All three rating agencies cited the March and May decisions by the FPSC in the base rate proceedings for Tampa Electric and PGS, respectively, as being supportive of credit quality.
Standard & Poors, Moodys 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 & Poors is BBB-, for Moodys is Baa3 and for Fitch is BBB-; thus all three credit rating agencies assign TECO Energy, TECO Finance and Tampa Electric Companys 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. Any future downgrades in credit ratings may affect our ability to borrow and may increase financing costs, which may decrease earnings (see the Risk Factors section).
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, 2009
Summary of Contingent Obligations
The following table summarizes the letters of credit and guarantees outstanding that are not included in the Summary of Contractual Obligations table above and not otherwise included in our Consolidated Financial Statements. These amounts represent guarantees by TECO Energy on behalf of consolidated subsidiaries. TECO Energy has no guarantees outstanding on behalf of unconsolidated or unrelated parties.
Contingent Obligations at Dec. 31, 2009